Subterranean well torpedo distributed acoustic sensing system and method

ABSTRACT

Provided in some embodiments is a method of distributed acoustic sensing in a subterranean well. The method including advancing a torpedo into a first portion of a wellbore of a subterranean well (the torpedo including a distributed acoustic sensing (DAS) fiber-optic (FO) umbilical that is physically coupled to a surface component and adapted to unspool from the torpedo as the torpedo advances in the wellbore, and an engine adapted to generate thrust to propel the torpedo), and activating the engine to generate thrust to propel advancement of the torpedo within a second portion of the wellbore such that at least some of the DAS FO umbilical is disposed in the second portion of the wellbore.

FIELD

Embodiments relate generally to developing hydrocarbon wells, and moreparticularly to deploying devices into hydrocarbon wells.

BACKGROUND

A well generally includes a wellbore (or a “borehole”) that is drilledinto the Earth to provide access to a geologic formation below theEarth's surface (or a “subsurface formation”). The well may facilitatethe extraction of natural resources, such as hydrocarbons or water, fromthe subsurface formation, facilitate the injection of substances, suchas water or gas, into the subsurface formation, or facilitate theevaluation and monitoring of the subsurface formation. In the petroleumindustry, hydrocarbon wells are often drilled to extract (or “produce”)hydrocarbons, such as oil and gas, from subsurface formations. The term“oil well” is often used to refer to a well designed to produce oil.Similarly the term “gas well” is often used to refer to a well designedto produce gas. In the case of an oil well, some natural gas istypically produced along with oil. A well producing both oil and naturalgas is sometimes referred to as an “oil and gas well” or an “oil well.”The term “hydrocarbon well” is often used to describe wells thatfacilitate the production of hydrocarbons, including oil wells and oiland gas wells.

Creating a hydrocarbon well typically involves several stages, includinga drilling stage, a completion stage and a production stage. Thedrilling stage involves drilling a wellbore into a subsurface formationthat is expected to contain a concentration of hydrocarbons that can beproduced. The portion of the subsurface formation expected to containhydrocarbons is often referred to as a “hydrocarbon reservoir,” orsimply a “reservoir.” The drilling process is normally facilitated by adrilling rig that sits at the Earth's surface. The drilling rig canprovide for operating a drill bit to cut the wellbore, hoisting,lowering and turning drill pipe and tools, circulating drilling fluidsin the wellbore, and generally controlling operations in the wellbore(often referred to as “down-hole” operations). The completion stageinvolves making the well ready to produce hydrocarbons. In someinstances, the completion stage includes installing casing pipe in thewellbore, cementing the casing pipe in place, perforating the casingpipe and cement, installing production tubing, installing down-holevalves for regulating production flow, and pumping fluids into thewellbore to fracture, clean or otherwise prepare the reservoir and wellto produce hydrocarbons. The production stage involves producinghydrocarbons from the reservoir by way of the well. During theproduction stage, the drilling rig is normally removed and replaced witha collection of valves at the surface (often referred to as “surfacevalves” or a “production tree”), and valves are installed in thewellbore (often referred to as “down-hole valves”). These surface anddown-hole valves can be operated to regulate pressure in the wellbore,to control production flow from the wellbore and to provide access tothe wellbore if needed. Sensors are often deployed at the surface or inthe wellbore to monitor the characteristics of the well. For example,pressure and temperature sensors may be deployed in the wellbore tomonitor pressure and temperature in the wellbore. A pump jack or othermechanism can provide lift that assists in extracting hydrocarbons fromthe reservoir, especially in instances in which the pressure in the wellis so low that the produced hydrocarbons do not flow freely to thesurface. Flow from an outlet valve of the production tree is normallyconnected to a distribution network of midstream facilities, such astanks, pipelines and transport vehicles, which transport the productionto downstream facilities, such as refineries and export terminals.

The various stages of creating a hydrocarbon well often includechallenges that are addressed to successfully develop the well and thesubsurface formation. During the each of the stages, a well operator mayneed to monitor conditions of the wellbore to assess a current state ofthe well and to generate and execute a plan to develop the well or othernearby wells. For example, during the production stage of a well, a welloperator may deploy devices, such as pressure and temperature sensors,in a wellbore to monitor pressure and temperature of production fluidsin the wellbore. Such measurements can be used to assess the current andhistorical production of the well which can, in turn, be used to developa field development plan (FDP) for the well and surrounding wells. TheFDP may specify target production rates, injection rates or otherparameters for the well and surrounding wells. A well operator mayconduct operations, such as adjusting production rates, injection ratesor other parameters, for the well or other wells in the same subsurfaceformation in accordance with the FDP in an effort to optimize productionfrom the subsurface formation.

SUMMARY

Applicant has recognized that deploying devices into a well can becritical to successfully operating the well and other wells in the sameformation. A well operator may benefit from understandingcharacteristics of a well extending into a subsurface formation whenmaking decisions regarding how best to operate the well and to developthe subsurface formation. For example, it can be critical for a welloperator to know current and historical bottom-hole pressure (BHP) andbottom-hole temperature (BHT) for a well when setting production ratesor injection rates for the well, or other wells in the same subsurfaceformation, to optimize production from the subsurface formation. Thus,it can be critical to place sensors, such as BHP sensors and BHTsensors, in appropriate positions within a wellbore of a hydrocarbonwell to acquire well data for the well, including BHP and BHT of thewell. As another example, it can be critical for a well operator to knowcharacteristics of the subsurface formation to determine when and whereto drill wells into the subsurface formation, and how to operate wellsin the formation. Thus, it can be critical to place formationmeasurement devices, such as seismic logging devices, to acquireformation data for the subsurface formation. The seismic logging devicescan include, for example, acoustic sensors, such as geophones.

Applicants have also recognized that existing techniques for deployingdevices into wells suffer from a variety of drawbacks. In someinstances, devices are deployed into a well by way of gravity. Forexample, a device may be suspend from a wireline that is unspooled fromthe surface to lower the wireline and the device into the wellbore. Thewireline may include, for example, an umbilical line that provides forpowering and communicating with the device. Although this technique canbe suitable for use in vertical wellbores, it may not be suitable foruse in horizontal wellbores. For example, if a wellbore includes ahorizontal portion, the device may travel down the vertical portion, tothe start of the horizontal portion, by way of gravity, but may stop (or“bottom out”) at the transition to the horizontal portion. As a result,the device and the wireline may not advance into the horizontal sectionof the wellbore. In some instances, tractors are used to convey devicesfurther into horizontal wellbores. For example, a tractor device may besuspended from a wireline that is unspooled from the surface to lowerthe tractor device and the trailing wireline into the wellbore, and thetractor may be driven to pull the tractor and the trailing wireline intothe horizontal portion of the wellbore. Although this technique canprovide increased access to the horizontal portion of a wellbore, it istypically limited by how far the tractor can pull the trailing wireline.For example, in the case of a lengthy horizontal portion, the tractormay not be capable of generating the power or traction necessary toadvance the tractor and the trailing wireline deep into or completelythrough the horizontal portion of the wellbore. Moreover, the wirelineitself may be damaged from friction as it is dragged across the walls ofwellbore. As a result, the wireline may need to have a ruggedencapsulation that can increase weight and, in turn, reduce theeffective range of a tractor pulling the wireline.

Recognizing these and other shortcomings of existing techniques,Applicant has developed novel systems and method for deploying devicesinto wells by way of a thrust-propelled well torpedo (TPWT) system. Insome embodiments, a TPWT system is employed to deploy devices, such assensors, into a wellbore of a hydrocarbon well, such as an oil well. Forexample, a TPWT having an engine and carrying a payload, such as sensorsor other devices, may be propelled deep into a wellbore of a hydrocarbonwell by way of thrust based propulsion.

In some embodiments, a TPWT includes a fiber optic (FO) umbilical thatis unspooled from the TPWT as it travels in a wellbore. For example, aTPWT may include a FO umbilical including a FO line that is wrapped (or“spooled”) around an integrated spool of the TPWT, and that is unspooledfrom the TPWT as it travels through the wellbore. An FO umbilical mayprovide for communication between the TPWT and a control system, such asa well control system located at the surface. For example, an upper end(or “up-hole end”) of a FO umbilical of a TPWT may be coupled to a wellcontrol system of a well, and a lower end (or “down-hole end”) of the FOumbilical may be coupled to a control system (or “controller”) of theTPWT. In such an embodiment, the FO umbilical may provide forcommunication of data between the well control system and the controlsystem of the TPWT.

In some embodiments, the data includes commands relating to controllingoperation of the TPWT. For example, the well control system may send, tothe controller of the TPWT by way of the FO umbilical, commandsdictating operation of the TPWT. In such an embodiment, the controllermay execute the commands by controlling corresponding operations of theTPWT. For example, the well control system may send, to the controllerof the TPWT by way of the FO umbilical, a command to ignite orextinguish the engine of the TPWT, and the controller may control a fuelsupply valve and an igniter of the engine to ignite the engine. In someembodiments, the data includes TPWT operational data relating tooperation of the TPWT. For example, the controller of the TPWT maymonitor and collect data regarding the operation of the engine, thecontroller or the payload, such as conditions sensed by sensors of thepayload, and send, to the well control system by way of the FOumbilical, TPWT operational data corresponding to the data collected.The TPWT data may, for example, include data that indicates whether theengine is ignited, that indicates a status of fins, rudders ordirectional thrust systems of the TPWT, that indicates a speed,orientation or location of the TPWT within the wellbore, or thatindicates conditions sensed by the sensors. In some embodiments, thewell control system generates the commands relating to controllingoperation of the TPWT based on the TPWT operational data received fromthe TPWT controller.

In some embodiments, deployment of a TPWT into a wellbore includes agravity-driven free-fall of the TPWT in the wellbore, followed by athrust-driven propulsion of the TPWT further into the wellbore. Forexample, a TPWT may be released into a free-fall through a first/upperportion of the wellbore (such as a vertical portion of the wellbore)and, upon reaching a trigger point (such as a predefined depth in thewellbore), the engine of the TPWT may be ignited to generate thrust thatpropels the TPWT in a second/lower portion of the wellbore (such as ahorizontal portion of the wellbore). The TPWT may come to rest in adeployment location in the second/lower portion of the wellbore.

In some embodiments, a body of a TPWT is formed of a material adapted todissolve under exposure to a wellbore environment. The material mayinclude, for example, a magnesium alloy. In such an embodiment, the TPWTmay come to rest in a deployment location within the wellbore, and thedissolvable body of the TPWT may dissolve (for example, over the courseof several hours, days or weeks), leaving behind the FO umbilical andany non-dissolvable portions of the TPWT, such as a payload ofnon-dissolvable sensors.

In some embodiments, the use of a dissolvable TPWT body is advantageous.For example, a dissolvable TPWT body can eliminate a need to retrievethe TPWT. Traditional wireline devices are typically lowered into awellbore and later retrieved (for example, pulled) from the wellbore forreuse or to keep the wireline device from blocking the wellbore. Incontrast, a dissolvable TPWT body may be less expensive to produce,eliminating a need for reuse, and may simply dissolve to reduce anyblockage of the wellbore. As a result, use of a dissolvable TPWT bodycan eliminate the need for a retrieval operation, or at least simplifyany associated retrieval operation. A retrieval operation, if conducted,may simply include pulling the relatively thin and light FO umbilicaland any non-dissolvable portions of the TPWT that remain coupled to theFO umbilical, such as undissolved sensors. Moreover, given that the bodyof the TPWT may not need to be retrieved, the FO umbilical can berelatively thin and lightweight, which can be advantageous for at leastthe reasons described here, including extending a range of the TPWT, orfacilitating severing of the FO umbilical, if needed.

In some embodiments, use of a FO umbilical is advantageous. For example,in contrast to a relatively heavy line, such as a traditional wirelineumbilical, a FO umbilical may have a relatively light weight. This mayhelp to reduce the overall weight of a TPWT, which can enable the TPWTto travel farther into the wellbore or to carry a heavier payload. As afurther example, in contrast to a relatively thick line, such as atraditional wireline umbilical, a FO umbilical may have a relativelysmall diameter and can be severed easily. This may enable a FO umbilicalto be run through relatively small ports in the well system, such asthrough a valve of a wellhead, and may enable the FO umbilical to beeasily severed if needed. For example, in the case of an emergencyoperation that requires closing of a wellhead valve having a FOumbilical run through the valve, the valve can simply be closed, withthe closing action severing the FO umbilical. In contrast, a traditionalwireline may be too thick or tough to be easily severed by a wellheadvalve. Thus, the wireline may need to be removed from the wellbore orsevered in a separate operation, prior to closing the wellhead valve.This can result in significant delays that are undesirable, especiallyin time sensitive emergency operations.

In some embodiments, unspooling of a FO umbilical from a TPWT isadvantageous due to a reduction of friction and drag on the FO umbilicalduring deployment of the TPWT in a wellbore. For example, in a situationin which a line extends from a spool at the surface and is attached to adevice to be lowered into a wellbore, the line may be unspooled from thesurface to lower the device into the wellbore. As a result, the line maymove through the wellbore along with the device and rub against theabrasive walls of the wellbore. The resulting friction can physicallywear the line and create a frictional force that resists advancement ofthe device in the wellbore. In an effort to address these issues, such aline may be provided with a durable exterior coating. Unfortunately,this can add weight and thickness to the line which can, in turn, limita range of travel of the device or inhibit severing of the line. Incontrast, unspooling of a FO umbilical from a TPWT as it travels throughthe wellbore may prevent significant movement of the FO umbilical withinthe wellbore. For example, a portion of a FO umbilical unspooled from aTPWT as it passes a given depth may remain at that depth as the TPWTcontinues to travel down the wellbore and unspool an additional lengthof the FO umbilical. During deployment, the FO umbilical may lay againstthe wall of the wellbore, but it should not experience any significantmovement or rubbing along the wellbore. As a result, the FO umbilicalmay not generate friction that significantly resists advancement of theTPWT and may not require a durable exterior coating, which can help toreduce the weight and thickness of the FO umbilical. This can, in turn,extend a range of travel of the device or facilitate severing of the FOumbilical.

A TPWT can include various features that facilitate deployment in ahydrocarbon well. In some embodiments, a TPWT includes an integratedspool for housing a FO umbilical that is unspooled from the TPWT as ittravels through a wellbore of a well. For example, a body of a TPWT mayinclude a recess in an exterior surface of the body into which the FOumbilical can be wound. The integrated spool may provide for simpleloading of the FO umbilical onto the TPWT, may protect the FO lineduring transport and travel in a wellbore environment, and mayfacilitate the unspooling of the FO umbilical during travel in thewellbore environment.

In some embodiments, a TPWT includes navigational elements, such asfins, rudders, or directional thrust systems. A fin of a TPWT mayinclude a fixed stabilizer that reduces aerodynamic side slip of theTPWT. A rudder of a TPWT may include a movable stabilizer that providesfor steering of the TPWT. A directional thrust system of a TPWT mayinclude device for directing thrust generated by an engine of the TPWT.For example, a directional thrust system of a TPWT may include a gimbalmounted exhaust nozzle that can be swiveled to guide a direction offorward thrust generated by an engine of the TPWT. As a further example,a directional thrust system of a TPWT may include a reverse thrustsystem including a bypass conduit (or “passage”) that can be selectivelyengaged to direct thrust generated by an engine of the TPWT in a forwarddirection. This may generate “reverse thrust” to slow or stop movementof the TPWT in the forward direction.

In some embodiments, a TPWT includes a jet-pump engine. A jet-pumpengine of a TPWT may provide for the introduction of wellbore fluid intocombusted gases of the engine to enhance the thrust generated by theTPWT. For example, a TPWT may include a jet-pump engine having a wellfluid inlet that directs wellbore fluid into hot combusted gas prior toit being exhausted through an exit nozzle. The mixture of fluid and hotcombusted gas may cause the wellbore fluid to expand, resulting in arelative increase in thrust for the amount of propellant combusted togenerate the gas. This can help to decrease the amount of propellantneeded or increase the effective range of the TPWT.

In some embodiments, a TPWT includes an integrated locating device, suchas a casing collar locator (CCL). A CCL may include a device for sensinglocations of transitions between adjacent sections of casing, tubing, orother conduit. For example, a TPWT may include a CCL including first andsecond electromagnetic coils integrated into a body of the TPWT. Thecoils may be electrified to create an electromagnet that is capable ofsensing changes in magnetic field caused by changes in thickness of asurrounding metal tubular, such as casing or tubing. As the TPWT travelsthrough a wellbore and passes a location at which a surrounding metaltubular changes in thickness, such as at a connection between adjacentsections of casing, the first and second electromagnetic coils candetect the change in magnetic field in sequence, and the change can beattributed to the TPWT being located at or passing the location of thechange. The locations, such as locations of connections, are typicallyknown for a well based on documentation of the construction of the welland, thus, the associated changes in magnetic flux can be used todetermine a location of the TPWT in the wellbore of the well.

In some embodiments, a TPWT is used to deploy various types of sensorsor other devices into a well. For example, a TPWT may include a payloadof sensors, such as such as BHP sensors or BHT sensors. Deployment ofthe TPWT in a wellbore of a well may provide for positioning the sensorsat a deployment location within the wellbore, where the sensors can beoperated to acquire data, such as BHP data and BHT data, respectively,for the well.

In some embodiments, a TPWT is used to deploy sensors, such as a FOline, for distributed acoustic sensing (DAS). DAS may be used, forexample, for vertical seismic profiling of a well. A DAS FO umbilicalmay include a FO line capable of sensing seismic events along itslength. Such a DAS FO umbilical may be run into a wellbore of a well todistribute the FO line along a length of the wellbore where it can beoperated to sense seismic events at discrete locations along the lengthof the wellbore. Seismic events can be generated, for example, by way ofan array of seismic sources located at the surface that are operated totransmit seismic signals into a portion of a formation surrounding thewellbore. In some embodiments, a TPWT is spooled with a DAS FO umbilicalthat is unspooled for the TPWT as it travels in a wellbore of a well, inturn distributing a FO line along a length of the wellbore. The use ofthe TPWT may enable the DAS FO umbilical to be distributed deep into thewellbore with a relatively low amount of rubbing and wear of the DAS FOumbilical. In some embodiments, the DAS FO umbilical is sized tofacilitate contact between the DAS FO umbilical and a lining of thewellbore, such as a metallic casing or tubing. For example, the DAS FOumbilical may have a length that is about 125% of a length portion ofthe wellbore to be lined to facilitate the DAS FO expanding radial toadhere (or “stick”) to the tubular walls by way of surface tension. Theextended length may promote the DAS FO umbilical taking a spiral orhelical shape as it sticks to the interior walls. A resulting couplingwith the walls of a tubular can help to reduce attenuation of seismicsignals sensed by the DAS FO umbilical.

In some embodiments, a DAS FO umbilical includes a U-bend style DAS FOline. A U-bend DAS FO line may include a FO line having a first DAS FOline segment terminating into a FO U-bend that is coupled to a secondDAS FO line segment. When deployed, the U-bend may be depositeddown-hole, with the first and second DAS FO line segments extending tothe surface. The ends of the first and second DAS FO line segments maybe coupled to other U-bend DAS FO line segments deployed in other wellsto provide a contiguous DAS FO line that extends into multiple wells. Aninterrogator may be coupled to the continuous DAS FO line to monitorseismic events sensed by the DAS FO line disposed in the well or wells.

In some embodiments, a U-bend of a DAS FO line includes a round bend inthe DAS FO line connecting adjacent first and second segments of the DASFO line. In some embodiments, a U-bend of a DAS FO line includes a“mini-bend” connection connecting adjacent first and second segments ofthe DAS FO line. In some embodiments, a U-bend DAS FO line is wrappedabout an integrated spool of a TPWT to maintain the curved shape of theU-bend of the FO line. For example, a U-bend DAS FO line may be wrappedabout a circumference of an integrated spool of a TPWT to maintain thecurved shape of the U-bend of the FO line. As a further example, aU-bend DAS FO line may be wrapped about a circumference of an integratedspool of a TPWT with the U-bend secured to a face of the integratedspool (for example, tucked under wraps of the U-bend DAS FO line) tomaintain the curved shape of the U-bend of the FO line. In an embodimentin which a U-bend DAS FO line includes a mini-bend, the U-bend DAS FOline may be wrapped about a circumference of an integrated spool of aTPWT, with the mini-bend secured to a face of the integrated spool (forexample, tucked under wraps of the U-bend DAS FO line) to secure andprotect the mini-bend of the FO line.

Provided in some embodiments is a method of deploying DAS sensors in asubterranean well. The method including: releasing a torpedo intogravity-driven advancement within a first portion of a wellbore of asubterranean well (the torpedo including: a DAS FO umbilical that isphysically coupled to a surface component and adapted to unspool fromthe torpedo as the torpedo advances in the wellbore; and an engineadapted to generate thrust to propel advancement of the torpedo in thewellbore); determining that the torpedo has reached a trigger pointwithin the wellbore; and activating, in response to determining that thetorpedo has reached the trigger point within the wellbore, the engine togenerate forward thrust to propel the torpedo within a horizontalportion of the wellbore such that at least some of the DAS FO umbilicalis disposed in the horizontal portion of the wellbore, and the torpedocomes to rest at a deployment location within the wellbore.

Provided in some embodiments is a method of distributed acoustic sensingin a subterranean well, the method including: advancing a torpedo into afirst portion of a wellbore of a subterranean well (the torpedoincluding: a DAS FO umbilical that is physically coupled to a surfacecomponent and adapted to unspool from the torpedo as the torpedoadvances in the wellbore; and an engine adapted to generate thrust topropel the torpedo); and activating the engine to generate thrust topropel advancement of the torpedo within a second portion of thewellbore such that at least some of the DAS FO umbilical is disposed inthe second portion of the wellbore.

In some embodiments, subsequent to the torpedo coming to rest in thedeployment location, the DAS FO umbilical extends from the surfacecomponent into the second portion of the wellbore. In certainembodiments, the method further includes, subsequent to the torpedocoming to rest at the deployment location within the wellbore,conducting a seismic operation including sensing seismic events by wayof the DAS FO umbilical unspooled in the wellbore. In some embodiments,the method further includes, positioning a plurality of seismic sourcesat surface locations, where the seismic operation further includesoperating the seismic sources to generate seismic signals, and where theseismic events correspond to the seismic signals generated. In certainembodiments, the method further includes, subsequent to the torpedocoming to rest at the deployment location within the wellbore,conducting a fluid flow monitoring operation including sensing fluidflow by way of the DAS FO umbilical unspooled in the wellbore. In someembodiments, the method further includes, subsequent to the torpedocoming to rest at the deployment location within the wellbore,conducting a leak monitoring operation including sensing a leak by wayof the integrated acoustic sensors of the DAS FO umbilical unspooled inthe wellbore. In certain embodiments, the DAS FO umbilical includes asingle segment of FO line. In some embodiments, the DAS FO line includesa U-bend style DAS FO line including a first segment of the DAS FO lineand a second segment of the DAS FO line connected by way of a U-bend. Incertain embodiments, the torpedo includes a cylindrical spool, and themethod further includes wrapping the U-bend about a circumference of thespool, and wrapping the first and second segments of the DAS FO lineabout the U-bend wrapped about the circumference of the spool. In someembodiments, the torpedo includes a cylindrical spool, and the methodfurther includes disposing the U-bend on a surface of the spool, andwrapping the first and second segments of the DAS FO line about theU-bend disposed on the surface of the spool. In certain embodiments, theU-bend includes a mini-bend connector. In some embodiments, a firstportion of the DAS FO umbilical including the a first segment of the DASFO, the second segment of the DAS FO line and the U-bend is disposed inthe wellbore using the torpedo, and the method further includesdeploying a second portion of the DAS FO umbilical into a secondwellbore using a second torpedo, the second portion of the DAS FOumbilical including a third segment of the DAS FO line and a fourthsegment of the DAS FO line connected by way of a second U-bend. Incertain embodiments, the method further includes conducting a seismicoperation including sensing seismic events by way of the first portionof the DAS FO umbilical disposed in the wellbore and the second portionof the DAS FO umbilical disposed in the second wellbore. In someembodiments, the torpedo includes a body formed of a dissolvablematerial adapted to dissolve in the wellbore, and the method furtherincludes leaving the torpedo at the deployment location such that thebody of the torpedo dissolves at the deployment location within thewellbore. In certain embodiments, the DAS FO umbilical is coupled to awell control system and is adapted to facilitate communication betweenthe torpedo and the well control system, and the method further includesthe well control system receiving data from the torpedo by way of theDAS FO umbilical. In some embodiments, the second portion of thewellbore includes a horizontal portion of the wellbore. In certainembodiments, the method further includes: determining that the torpedohas reached a trigger point within the wellbore, where the engine isactivated to generate the thrust in response to determining that thetorpedo has reached the trigger point within the wellbore. In someembodiments, the trigger point within the wellbore includes a predefineddepth within the wellbore. In certain embodiments, the first portion ofthe wellbore includes a vertical portion of the wellbore and the secondportion of the wellbore includes a horizontal portion of the wellbore,and the trigger point within the wellbore includes a point of transitionbetween the vertical portion of the wellbore and the horizontal portionof the wellbore.

Provided in some embodiments is a non-transitory computer readablestorage medium including program instructions stored thereon that areexecutable by a processor to cause the above described methodoperations.

Provided in some embodiments is a subterranean well torpedo systemincluding: a control system; and a torpedo including: a DAS FO umbilicalthat is physically coupled to a surface component and adapted to unspoolfrom the torpedo as the torpedo advances in the wellbore; and an engineadapted to generate thrust to propel the torpedo. The control systemadapted to: advance the torpedo into a first portion of the wellbore ofthe subterranean well; and activate the engine to generate thrust topropel the torpedo within a second portion of the wellbore such that atleast some of the DAS FO umbilical is disposed in the second portion ofthe wellbore.

In some embodiments, subsequent to the torpedo coming to rest in thedeployment location, the DAS FO umbilical extends from the surfacecomponent into the second portion of the wellbore. In certainembodiments, the control system is further adapted to, subsequent to thetorpedo coming to rest at the deployment location within the wellbore,conduct a seismic operation including sensing seismic events by way ofthe DAS FO umbilical unspooled in the wellbore. In some embodiments, aplurality of seismic sources are positioned at surface locations, andthe seismic operation further includes operating the seismic sources togenerate seismic signals, and where the seismic events correspond to theseismic signals generated. In certain embodiments, the control system isfurther adapted to, subsequent to the torpedo coming to rest at thedeployment location within the wellbore, conduct a fluid flow monitoringoperation including sensing fluid flow by way of the DAS FO umbilicalunspooled in the wellbore. In some embodiments, the control system isfurther adapted to, subsequent to the torpedo coming to rest at thedeployment location within the wellbore, conduct a leak monitoringoperation including sensing a leak by way of the DAS FO umbilicalunspooled in the wellbore. In certain embodiments, the DAS FO umbilicalincludes a single segment of FO line. In some embodiments, the DAS FOline includes a U-bend style DAS FO line including a first segment ofthe DAS FO line and a second segment of the DAS FO line connected by wayof a U-bend. In certain embodiments, the torpedo includes a cylindricalspool, and where the U-bend is wrapped about a circumference of thespool, with the first and second segments of the DAS FO line wrappedabout the U-bend wrapped about the circumference of the spool. In someembodiments, the torpedo includes a cylindrical spool, and where theU-bend is disposed on a surface of the spool, with the first and secondsegments of the DAS FO line wrapped about the U-bend disposed on thesurface of the spool. In certain embodiments, the U-bend includes amini-bend connector. In some embodiments, a first portion of the DAS FOumbilical includes the first segment of the DAS FO, the second segmentof the DAS FO line and the U-bend, the first portion of the DAS FO lineis disposed in the wellbore using the torpedo, and a second portion ofthe DAS FO umbilical is disposed in a second wellbore, the secondportion of the DAS FO umbilical including a third segment of the DAS FOline and a fourth segment of the DAS FO line connected by way of asecond U-bend. In certain embodiments, the control system is furtheradapted to conduct a seismic operation including sensing seismic eventsby way of the first portion of the DAS FO umbilical disposed in thewellbore and the second portion of the DAS FO umbilical disposed in thesecond wellbore. In some embodiments, the torpedo includes a body formedof a dissolvable material adapted to dissolve in the wellbore. Incertain embodiments, the DAS FO umbilical is coupled to a well controlsystem and is adapted to facilitate communication between the torpedoand the well control system. In some embodiments, the second portion ofthe wellbore includes a horizontal portion of the wellbore. In certainembodiments, the control system is further adapted to determine that thetorpedo has reached a trigger point within the wellbore, and the engineis activated to generate the thrust in response to determining that thetorpedo has reached the trigger point within the wellbore. In someembodiments, the trigger point within the wellbore includes a predefineddepth within the wellbore. In certain embodiments, the first portion ofthe wellbore includes a vertical portion of the wellbore and the secondportion of the wellbore includes a horizontal portion of the wellbore,and the trigger point within the wellbore includes a point of transitionbetween the first wellbore portion and the second wellbore portion ofthe wellbore. In some embodiments, the DAS FO umbilical has a lengththat is at least 25% greater than a distance between the surfacecomponent and a target deployment location within the wellbore.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is diagram that illustrates a well environment in accordance withone or more embodiments.

FIG. 2 is a diagram that illustrates a thrust-propelled well torpedo(TPWT) in accordance with one or more embodiments.

FIG. 3 is a diagram that illustrates a TPWT tree cap in accordance withone or more embodiments.

FIG. 4 is a diagram that illustrates deployment of a TPWT in accordancewith one or more embodiments.

FIGS. 5-8 are diagrams that illustrates example thrust-propelled welltorpedo (TPWTs) in accordance with one or more embodiments.

FIGS. 9 and 10 are diagrams that illustrates example well distributedacoustic sensing (DAS) using TPWTs in accordance with one or moreembodiments.

FIGS. 11 and 12 are diagrams that illustrates example spooling of U-bendstyle DAS fiber optic (FO) lines in accordance with one or moreembodiments.

FIG. 13 is a flowchart diagram that illustrates a method of DAS sensingusing a TPWT in accordance with one or more embodiments

FIG. 14 is a flowchart diagram that illustrates a method of deploying aTPWT into a well in accordance with one or more embodiments.

FIG. 15 is a diagram that illustrates an example computer system, inaccordance with one or more embodiments.

While this disclosure is susceptible to various modifications andalternative forms, specific embodiments are shown by way of example inthe drawings and will be described in detail. The drawings may not be toscale. It should be understood that the drawings and the detaileddescription are not intended to limit the disclosure to the particularform described, but are intended to disclose modifications, equivalentsand alternatives falling within the scope of the present disclosure asdefined by the claims.

DETAILED DESCRIPTION

Described are embodiments of novel systems and methods for deployingdevices into wells (e.g., a hydrocarbon well) by way of athrust-propelled well torpedo (TPWT) system. In some embodiments, a TPWTsystem is employed to deploy devices, such as sensors, into a wellboreof a hydrocarbon well, such as an oil well. For example, a TPWT havingan engine and carrying a payload, such as sensors or other devices, maybe propelled deep into a wellbore of a hydrocarbon well by way ofthrust-based propulsion.

In some embodiments, a TPWT includes a fiber optic (FO) umbilical thatis unspooled from the TPWT as it travels in a wellbore. For example, aTPWT may include a FO umbilical including a FO line that is wrapped (or“spooled”) around an integrated spool of the TPWT, and that is unspooledfrom the TPWT as it travels through the wellbore. An FO umbilical mayprovide for communication between the TPWT and a control system, such asa well control system located at the surface. For example, an upper end(or “up-hole end”) of a FO umbilical of a TPWT may be coupled to a wellcontrol system of a well, and a lower end (or “down-hole end”) of the FOumbilical may be coupled to a control system (or “controller”) of theTPWT. In such an embodiment, the FO umbilical may provide forcommunication of data between the well control system and the controlsystem of the TPWT.

In some embodiments, the data includes commands relating to controllingoperation of the TPWT. For example, the well control system may send, tothe controller of the TPWT by way of the FO umbilical, commandsdictating operation of the TPWT. In such an embodiment, the controllermay execute the commands by controlling corresponding operations of theTPWT. For example, the well control system may send, to the controllerof the TPWT by way of the FO umbilical, a command to ignite orextinguish the engine of the TPWT, and the controller may control a fuelsupply valve and an igniter of the engine to ignite the engine. In someembodiments, the data includes TPWT operational data relating tooperation of the TPWT. For example, the controller of the TPWT maymonitor and collect data regarding the operation of the engine, thecontroller or the payload, such as conditions sensed by sensors of thepayload, and send, to the well control system by way of the FOumbilical, TPWT operational data corresponding to the data collected.The TPWT data may, for example, include data that indicates whether theengine is ignited, that indicates a status of fins, rudders ordirectional thrust systems of the TPWT, that indicates a speed,orientation or location of the TPWT within the wellbore, or thatindicates conditions sensed by the sensors. In some embodiments, thewell control system generates the commands relating to controllingoperation of the TPWT based on the TPWT operational data received fromthe TPWT controller.

In some embodiments, deployment of a TPWT in a wellbore includes agravity-driven free-fall of the TPWT in the wellbore, followed by athrust-driven propulsion of the TPWT further into the wellbore. Forexample, a TPWT may be released into a free-fall through a first/upperportion of the wellbore (such as a vertical portion of the wellbore)and, upon reaching a trigger point (such as a predefined depth in thewellbore), the engine of the TPWT may be ignited to generate thrust thatpropels the TPWT in a second/lower portion of the wellbore (such as ahorizontal portion of the wellbore). The TPWT may come to rest in adeployment location in the second/lower portion of the wellbore.

In some embodiments, a body of a TPWT is formed of a material adapted todissolve under exposure to a wellbore environment. The material mayinclude, for example, a magnesium alloy. In such an embodiment, the TPWTmay come to rest in a deployment location within the wellbore, and thedissolvable body of the TPWT may dissolve (for example, over the courseof several hours, days or weeks), leaving behind the FO umbilical andany non-dissolvable portions of the TPWT, such as a payload ofnon-dissolvable sensors.

In some embodiments, the use of a dissolvable TPWT body is advantageous.For example, a dissolvable TPWT body can eliminate a need to retrievethe TPWT. Traditional wireline devices are typically lowered into awellbore and later retrieved (for example, pulled) from the wellbore forreuse or to keep the wireline device from blocking the wellbore. Incontrast, a dissolvable TPWT body may be less expensive to produce,eliminating a need for reuse, and may simply dissolve to reduce anyblockage of the wellbore. As a result, use of a dissolvable TPWT bodycan eliminate the need for a retrieval operation, or at least simplifyany associated retrieval operation. A retrieval operation, if conducted,may simply include pulling the relatively thin and light FO umbilicaland any non-dissolvable portions of the TPWT that remain coupled to theFO umbilical, such as undissolved sensors. Moreover, given that the bodyof the TPWT may not need to be retrieved, the FO umbilical can berelatively thin and lightweight, which can be advantageous for at leastthe reasons described here, including extending a range of the TPWT, orfacilitating severing of the FO umbilical, if needed.

In some embodiments, use of a FO umbilical is advantageous. For example,in contrast to a relatively heavy line, such as a traditional wirelineumbilical, a FO umbilical may have a relatively light weight. This mayhelp to reduce the overall weight of a TPWT, which can enable the TPWTto travel farther into the wellbore or to carry a heavier payload. As afurther example, in contrast to a relatively thick line, such as atraditional wireline umbilical, a FO umbilical may have a relativelysmall diameter and can be severed easily. This may enable a FO umbilicalto be run through relatively small ports in the well system, such asthrough a valve of a wellhead, and may enable the FO umbilical to beeasily severed if needed. For example, in the case of an emergencyoperation that requires closing of a wellhead valve having a FOumbilical run through the valve, the valve can simply be closed, withthe closing action severing the FO umbilical. In contrast, a traditionalwireline may be too thick or tough to be easily severed by a wellheadvalve. Thus, the wireline may need to be removed from the wellbore orsevered in a separate operation, prior to closing the wellhead valve.This can result in significant delays that are undesirable, especiallyin time sensitive emergency operations.

In some embodiments, unspooling of a FO umbilical from a TPWT isadvantageous due to a reduction of friction and drag on the FO umbilicalduring deployment of the TPWT in a wellbore. For example, in a situationin which a line extends from a spool at the surface and is attached to adevice to be lowered into a wellbore, the line may be unspooled from thesurface to lower the device into the wellbore. As a result, the line maymove through the wellbore along with the device and rub against theabrasive walls of the wellbore. The resulting friction can physicallywear the line and create a frictional force that resists advancement ofthe device in the wellbore. In an effort to address these issues, such aline may be provided with a durable exterior coating. Unfortunately,this can add weight and thickness to the line which can, in turn, limita range of travel of the device or inhibit severing of the line. Incontrast, unspooling of a FO umbilical from a TPWT as it travels throughthe wellbore may prevent significant movement of the FO umbilical withinthe wellbore. For example, a portion of a FO umbilical unspooled from aTPWT as it passes a given depth may remain at that depth as the TPWTcontinues to travel down the wellbore and unspool an additional lengthof the FO umbilical. During deployment, the FO umbilical may lay againstthe wall of the wellbore, but it should not experience any significantmovement or rubbing along the wellbore. As a result, the FO umbilicalmay not generate friction that significantly resists advancement of theTPWT and may not require a durable exterior coating, which can help toreduce the weight and thickness of the FO umbilical. This can, in turn,extend a range of travel of the device or facilitate severing of the FOumbilical.

A TPWT can include various features that facilitate deployment in ahydrocarbon well. In some embodiments, a TPWT includes an integratedspool for housing a FO umbilical that is unspooled from the TPWT as ittravels through a wellbore of a well. For example, a body of a TPWT mayinclude a recess in an exterior surface of the body into which the FOumbilical can be wound. The integrated spool may provide for simpleloading of the FO umbilical onto the TPWT, may protect the FO lineduring transport and travel in a wellbore environment, and mayfacilitate the unspooling of the FO umbilical during travel in thewellbore environment.

In some embodiments, a TPWT includes navigational elements, such asfins, rudders, or directional thrust systems. A fin of a TPWT mayinclude a fixed stabilizer that reduces aerodynamic side slip of theTPWT. A rudder of a TPWT may include a movable stabilizer that providesfor steering of the TPWT. A directional thrust system of a TPWT mayinclude device for directing thrust generated by an engine of the TPWT.For example, a directional thrust system of a TPWT may include a gimbalmounted exhaust nozzle that can be swiveled to guide a direction offorward thrust generated by an engine of the TPWT. As a further example,a directional thrust system of a TPWT may include a reverse thrustsystem including a bypass conduit (or “passage”) that can be selectivelyengaged to direct thrust generated by an engine of the TPWT in a forwarddirection. This may generate “reverse thrust” to slow or stop movementof the TPWT in the forward direction.

In some embodiments, a TPWT includes a jet-pump engine. A jet-pumpengine of a TPWT may provide for the introduction of wellbore fluid intocombusted gases of the engine to enhance the thrust generated by theTPWT. For example, a TPWT may include a jet-pump engine having a wellfluid inlet that directs wellbore fluid into hot combusted gas prior toit being exhausted through an exit nozzle. The mixture of fluid and hotcombusted gas may cause the wellbore fluid to expand, resulting in arelative increase in thrust for the amount of propellant combusted togenerate the gas. This can help to decrease the amount of propellantneeded or increase the effective range of the TPWT.

In some embodiments, a TPWT includes an integrated locating device, suchas a casing collar locator (CCL). A CCL may include a device for sensinglocations of transitions between adjacent sections of casing, tubing, orother conduit. For example, a TPWT may include a CCL including first andsecond electromagnetic coils integrated into a body of the TPWT. Thecoils may be electrified to create an electromagnet that is capable ofsensing changes in magnetic field caused by changes in thickness of asurrounding metal tubular, such as casing or tubing. As the TPWT travelsthrough a wellbore and passes a location at which a surrounding metaltubular changes in thickness, such as at a connection between adjacentsections of casing, the first and second electromagnetic coils candetect the change in magnetic field in sequence, and the change can beattributed to the TPWT being located at or passing the location of thechange. The locations, such as locations of connections, are typicallyknown for a well based on documentation of the construction of the welland, thus, the associated changes in magnetic flux can be used todetermine a location of the TPWT in the wellbore of the well.

In some embodiments, a TPWT is used to deploy various types of sensorsor other devices into a well. For example, a TPWT may include a payloadof sensors, such as such as BHP sensors or BHT sensors. Deployment ofthe TPWT in a wellbore of a well may provide for positioning the sensorsat a deployment location within the wellbore, where the sensors can beoperated to acquire data, such as BHP data and BHT data, respectively,for the well.

In some embodiments, a TPWT is used to deploy sensors, such as a FOline, for distributed acoustic sensing (DAS). DAS may be used, forexample, for vertical seismic profiling of a well. A DAS FO umbilicalmay include a FO line capable of sensing seismic events along itslength. Such a DAS FO umbilical may be run into a wellbore of a well todistribute the FO line along a length of the wellbore where it can beused to sense seismic events at discrete locations along the length ofthe wellbore. Seismic event can be generated, for example, by way of anarray of seismic sources located at the surface that are operated totransmit seismic signals into a portion of a formation surrounding thewellbore. In some embodiments, a TPWT is spooled with a DAS FO umbilicalthat is unspooled for the TPWT as it travels in a wellbore of a well, inturn distributing the FO line along a length of the wellbore. The use ofthe TPWT may enable the DAS FO umbilical to be distributed deep into thewellbore with a relatively low amount of rubbing and wear of the DAS FOumbilical. In some embodiments, the DAS FO umbilical is sized tofacilitate contact between the DAS FO umbilical and a lining of thewellbore, such as a metallic casing or tubing. For example, the DAS FOumbilical may have a length that is about 125% of a length portion ofthe wellbore to be lined to facilitate the DAS FO expanding radial toadhere (or “stick”) to the tubular walls by way of surface tension. Theextended length may promote the DAS FO umbilical taking a spiral orhelical shape as it sticks to the interior walls. A resulting couplingwith the walls of a tubular can help to reduce attenuation of seismicsignals sensed by the DAS FO umbilical.

In some embodiments, a DAS FO umbilical includes a U-bend style DAS FOline. A U-bend DAS FO line may include a FO line having a first DAS FOline segment terminating into a FO U-bend that is coupled to a secondDAS FO line segment. When deployed, the U-bend may be depositeddown-hole, with the first and second DAS FO line segments extending tothe surface. The ends of the first and second DAS FO line segments maybe coupled to other U-bend DAS FO line segments deployed in other wellsto provide a contiguous DAS FO line that extends into multiple wells. Aninterrogator may be coupled to the continuous DAS FO line to monitorseismic events sensed by the DAS FO line disposed in the well or wells.

In some embodiments, a U-bend of a DAS FO line includes a round bend inthe DAS FO line connecting adjacent first and second segments of the DASFO line. In some embodiments, a U-bend of a DAS FO line includes a“mini-bend” connection connecting adjacent first and second segments ofthe DAS FO line. In some embodiments, a U-bend DAS FO line is wrappedabout an integrated spool of a TPWT to maintain the curved shape of theU-bend of the FO line. For example, a U-bend DAS FO line may be wrappedabout a circumference of an integrated spool of a TPWT to maintain thecurved shape of the U-bend of the FO line. As a further example, aU-bend DAS FO line may be wrapped about a circumference of an integratedspool of a TPWT with the U-bend secured to a face of the integratedspool (for example, tucked under wraps of the U-bend DAS FO line) tomaintain the curved shape of the U-bend of the FO line. In an embodimentin which a U-bend DAS FO line includes a mini-bend, the U-bend DAS FOline may be wrapped about a circumference of an integrated spool of aTPWT, with the mini-bend secured to a face of the integrated spool (forexample, tucked under wraps of the U-bend DAS FO line) to secure andprotect the mini-bend of the FO line.

Although certain embodiments are described with regard to a hydrocarbonwell for the purpose of illustration, embodiments can be employed inother types of subterranean wells, such as water wells.

FIG. 1 is a diagram that illustrates a well environment 100 inaccordance with one or more embodiments. In the illustrated embodiment,the well environment 100 includes a reservoir (“reservoir”) 102 locatedin a subsurface formation (“formation”) 104, and a well system (“wellsystem”) 106. In some embodiments, the well system 106 includes a TPWTsystem 110. As described here, in some embodiments, the TPWT system 110is employed to deploy devices, such as BHT sensors, BHP sensors or DASsensors, into a wellbore of the well system 106.

The formation 104 may include a porous or fractured rock formation thatresides underground, beneath the Earth's surface (“surface”) 112. Thereservoir 102 may be a hydrocarbon reservoir defined by a portion of theformation 104 that contains (or that is at least determined to containor expected to contain) a subsurface pool of hydrocarbons, such as oiland gas. The formation 104 and the reservoir 102 may each includedifferent layers of rock having varying characteristics, such as varyingdegrees of permeability, porosity, and fluid saturation. In the case ofthe well system 106 being operated as a production well, the well system106 may facilitate the extraction of hydrocarbons (or “production”) fromthe reservoir 102. In the case of the well system 106 being operated asan injection well, the well system 106 may facilitate the injection ofsubstances, such as water or gas, into the formation 104 or thereservoir 102. In the case of the well system 106 being operated as amonitoring well, the well system 106 may facilitate the monitoring ofvarious characteristics of the formation 104 or the reservoir 102, suchreservoir pressure.

The well system 106 may include a hydrocarbon well (or “well”) 114 and awell operating system 116. The well operating system 116 may includecomponents for developing and operating the well 114, including a wellcontrol system 118 and the TPWT system 110. The well control system 118may control various operation aspects of the well system 106, such aswell drilling operations, well completion operations, well productionoperations or well and formation monitoring operations. As described, insome embodiments, the well control system 118 controls operation of theTPWT system 110 to deploy devices, such as BHT sensors, BHP sensors orDAS sensors, into a wellbore of the well 114. In some embodiments, thewell control system 118 includes a computer system that is the same asor similar to that of computer system 2000 described with regard to atleast FIG. 15.

The well 114 may include a wellbore (or “borehole”) 120. The wellbore120 may include a bored hole that extends from the surface 112 into atarget zone of the formation 104, such as the reservoir 102. An upperend of the wellbore 120, at or near the surface 112, may be referred toas the “up-hole” end of the wellbore 120. A lower end of the wellbore120, terminating in the formation 104, may be referred to as the“down-hole” end of the wellbore 120. The wellbore 120 may be created,for example, by a drill bit boring through the formation 104 and thereservoir 102. The wellbore 120 may provide for the circulation ofdrilling fluids during drilling operations, the flow of hydrocarbons,such as oil or gas, from the reservoir 102 to the surface 112 duringproduction operations, the injection of substances, such as water orgas, into the formation 104 or the reservoir 102 during injectionoperations, or the communication of monitoring devices, such as sensorsor logging tools, into one or both of the formation 104 and thereservoir 102 during monitoring operations, such as in-situ sensing orlogging operations. The wellbore 120 may include a motherbore 122 andone or more lateral bores 124.

The well 114 may include completion elements installed in the wellbore120, such as casing 126. The casing 126 may include, for example,tubular sections of steel casing pipe lining an inside diameter of thewellbore 120. In some embodiments, the casing 126 includes a fillermaterial, such as casing cement, deposited in the annular region locatedbetween the exterior of the casing pipe of the casing 126 and the wallsof the wellbore 120. In some embodiments, the casing 126 includes casingcollars 128 defined by variations in the thickness of the casing pipe orjoints between adjacent sections of casing pipe that form the casing126. As described, the casing collars 128, or collars of other elementsdisposed in the wellbore 120, may be detectable by a casing collarlocator (CCL) device as it is passed through the wellbore 120. Portionsof the wellbore 120 having casing 126 installed may be referred to as a“cased” portions of the wellbore 120. Portions of the wellbore 120 nothaving casing 126 installed may be referred to as an “open-holed” or“un-cased” portions of the wellbore 120. For example, in the illustratedembodiment, the upper portion of the wellbore 120 having casing 126installed may be referred to as a “cased” portion of the wellbore 120,and the lower portion of the wellbore 120 below (or “down-hole” from) alower end of the casing 126 may be referred to as an “un-cased” (or“open-holed”) portion of the wellbore 120. In some embodiments,“down-hole” devices are positioned in the wellbore 120 to monitorconditions in the wellbore 120 or to perform operations in the wellbore120. For example, BHP sensors and BHT sensors may be disposed in thewellbore 120 to measure BHP and BHT in the wellbore 120.

The well 114 may include surface components, such as a wellhead 130. Thewellhead 130 may include a device provided at an up-hole end of thewellbore 120 to provide a structural and pressure-containing interfacebetween the wellbore 120 and drilling and production equipment of thewell system 106. For example, the wellhead 130 may include a structurehaving a passage that provides access to the wellbore 120 and thatsupports the weight of the casing 126 or other down-hole componentssuspended in the wellbore 120. The wellhead 130 may include seals andvalves that regulate access to the wellbore 120. During drillingoperations, a blowout preventer may be coupled to the wellhead 130 tocontrol pressure in the wellbore 120. During production operations, aproduction tree may be coupled to the wellhead 130 to control productionflow rates and pressure. As described here, in some embodiments, a TPWTtree cap is coupled to the wellhead 130 to facilitate deployment of aTPWT into the wellbore 120.

In some embodiments, the well control system 118 stores, or otherwisehas access to, well data 132. The well data 132 may include data that isindicative of various characteristics of the well 114, the formation 104or the reservoir 102. The well data 132 may include, for example, a welllocation, a well trajectory, well logs, or well and formationcharacteristics. A well location may include coordinates defining alocation at which the up-hole end of the wellbore 120 penetrates theEarth's surface 112. A well trajectory for a well may includecoordinates defining a path of a wellbore of the well. For example, awell trajectory for the wellbore 120 of FIG. 1 may include coordinatesof a path of the motherbore 122 and the lateral bore 124. In someembodiments, the well data 132 for a well includes casing collarlocations defining the depths at which casing collars are located in thewellbore of the well.

In some embodiments, the well control system 118 stores, or otherwisehas access to, TPWT parameters 134. The TPWT parameters 134 may, forexample, specify parameters for deploying a TPWT into the wellbore 120of the well 114. In some embodiments, the TPWT parameters 134 specify apredefined trigger point. The trigger point may define a location, suchas a depth in the wellbore 120 or a time after release into a free-fall,at which a TPWT should transition from a free-fall to propelledoperation. In some embodiments, the TPWT parameters 134 specify apredefined route. The route may define a path within the wellbore 120,such as a path through the vertical section of the motherbore 122 andextending into a horizontal section of the motherbore 122 or the lateral124, to be traversed by a TPWT in the wellbore 120. The TPWT parameters134 may be predefined, for example, by a well operator.

In some embodiments, the TPWT system 110 includes a thrust-propelledtorpedo (TPWT) 140, a TPWT umbilical (“umbilical”) 142 and a TPWT treecap (“tree cap”) 144. As described, the TPWT system 110 may be employedto deploy devices, such as BHT sensors, BHP sensors or DAS sensors, intothe wellbore 120 of the well 114. In some embodiments, the umbilical 142is a fiber optic (FO) umbilical formed of a FO line. The FO line mayprovide for FO communication of data between the TPWT 140 and the wellcontrol system 118. In some embodiments, the umbilical 142 does notinclude a conduit for the transfer of electrical power. For example, theumbilical 142 may not provide for the communication of operational powerfrom the well control system 118 to the TPWT 140. As described, in someembodiments, the umbilical 142 includes a DAS FO line capable of sensingseismic events along a length of the DAS FO line, and deployment of theumbilical into the well 114 using the TPWT 140 may provide forpositioning of the FO line along a length of the wellbore 120 of thewell 114.

FIG. 2 is a diagram that illustrates a TPWT 140 in accordance with oneor more embodiments. In some embodiments, the TPWT 140 includes a TPWTbody (“body”) 200, a TPWT engine (“engine”) 202, a TPWT payload(“payload”) 204, an integrated TPWT spool (“spool”) 206, and a TPWTcontroller 208. The engine 202 may include a solid propellant drivenengine that is operable to generate thrust that propels advancement ofthe TPWT 140 in the wellbore 120. The thrust may be generated, forexample, by a jet of gas or liquid that is expelled from the engine 202.In some embodiments, such a jet may be expelled in a backward directionto generate forward thrust that provides for forward advancement of theTPWT 140 (for example, advancement toward a down-hole end of thewellbore 120). In some embodiments, some or all of the jet may bedirected in forward direction to generate reverse thrust that regulatesforward advancement of the TPWT 140, or that causes the TPWT 140 to movein a reverse direction (for example, movement “backward” toward anup-hole end of the wellbore 120). The payload 204 may include varioustypes of devices, such as such as BHP sensors or BHT sensors. In someembodiments, the umbilical 142 is the payload 204. For example, where itis desirable to deploy a DAS FO line into the wellbore 120, the DAS FOline may serve as the umbilical 142 and be the payload 204.

The TPWT controller 208 may provide for monitoring and controllingoperation of the TPWT 140 or communicating with devices external to theTPWT 140, such as the well control system 118. In some embodiments, theTPWT controller 208 includes a processor 218, memory 220, and a localpower source 222. The local power source 222 may be, for example, abattery. The local power source 222 may supply power for operating thecontroller 208 or other devices of the TPWT 140, such as sensors,valves, igniters, navigational elements or the payload 204.

In some embodiments, the TPWT controller 208 may monitor the status ofvarious elements of the TPWT 140. For example, the TPWT controller 208may monitor the operational status of the engine 202, of navigationalelements of the TPWT 140 (such as the position of stabilizers and areverse thrust system), of sensors of the TPWT 140 (such as a CCL), orof the payload 204 of the TPWT 140 (such as BHP sensors or BHT sensors).The controller 208 may transmit corresponding TPWT operational data tothe well control system 118 by way of the umbilical 142.

In some embodiments, the TPWT controller 208 may control operationalaspects of the TPWT 140. For example, the TPWT controller 208 mayreceive commands relating to controlling operation of the TPWT 140, andmay execute the commands by controlling corresponding operations of theTPWT 140. The commands may be received from the well control system 118by way of the umbilical 142. In some embodiments, the TPWT controller208 includes a computer system that is the same as or similar to that ofcomputer system 2000 described with regard to at least FIG. 15. Althoughsome embodiments are described with regard to the well control system118 sending commands and the TPWT controller 208 executing the commandsand reporting operational data to the well control system 118,embodiments can include the TPWT controller 208 executing operationaltasks independent of the well control system 118. For example, the TPWTcontroller 208 may process the TPWT operational data locally todetermine a status of the TPWT 140 and a corresponding operational task,and may, in turn, control operation of the TPWT 140 to execute the task.For example, upon the controller 208 determining that the TPWT 140 hasreached a target point in the wellbore 120, the TPWT 140 may initiateignition of the engine 202.

In some embodiments, the body 200 of the TPWT 140 is formed of amaterial adapted to dissolve under exposure to a wellbore environment.The body 200 may, for example, be formed of a magnesium alloy that isexpected to dissolve in the wellbore 120. In such an embodiment, theTPWT 140 may come to rest in a deployment location within the wellbore120, and the dissolvable body 200 of the TPWT 140 may dissolve (forexample, over the course of several hours, days or weeks), leavingbehind the umbilical 142 and any non-dissolvable portions of the TPWT140, such as the payload 204 or the controller 208, at the deploymentlocation.

In some embodiments, the body 200 is cylindrical in shape, having a coneshaped leading end (or “nose”) 210. Thrust generated by the engine 202may be expelled backward (in the direction of arrow 212), from atrailing end (or “tail end”) 214 of the body 200, to generate forwardthrust to propel the TPWT 140 forward (in the direction of arrow 216).For example, combusted gas generated by the engine 202 may be expelledbackward, through an exit nozzle of the engine 202 located at the tailof the body 200 to generate forward thrust to propel the TPWT 140forward (for example, toward a down-hole end of the wellbore 120). Insome embodiments, some or all of the thrust generated by the engine 202is selectively expelled forward (in the direction of arrow 216), fromthe leading end 210 of the body 200, to generate reverse thrust to slowor stop forward advancement of the TPWT 140. For example, at least someof the combusted gas generated by the engine 202 may be expelled in aforward direction to generate reverse thrust to slow or stop forwardadvancement of the TPWT 140. The amount of forward or reverse thrust maybe controlled to regulate the speed of the TPWT 140 or to cause the TPWTto come to rest at or near a given deployment location in the wellbore120. In some embodiments, the reverse thrust may be of a sufficientmagnitude to cause the TPWT 140 to move in reverse (for example, to move“backward” toward an up-hole end of the wellbore 120).

In some embodiments, the spool 206 provides a location for housing theumbilical 142 at the TPWT 140. The spool 206 may enable the umbilical142 to be unspooled from the TPWT 140 as the TPWT 140 travels throughthe wellbore 120 of the well 114. For example, the spool 206 may includea circumferential depression (or “recess”) that extends along a lengthof an exterior of the cylindrical body 200. The umbilical 142 may bewound onto the spool 206 (for example, the umbilical may be wound aboutthe body 200, in the recess) with an up-hole end of the umbilical 142physically coupled to a surface component, such as the TPWT tree cap144. During a deployment of the TPWT 140 into the wellbore 120, theumbilical 142 may be unwound (or “unspooled”) from the spool 206 as theTPWT 140 advances down the wellbore 120. In some embodiments, the recessof the spool 206 is of sufficient depth such that windings of theumbilical 142 loaded onto the spool 206 do not protrude radially outwardfrom the recess. Such a spool 206 may provide for simple loading of theumbilical 142 onto the TPWT 140, may protect the umbilical 142 duringassembly and transport of the TPWT 140 and during travel of the TPWT 140in the wellbore 120, and may facilitate simple unspooling of theumbilical 142 from the TPWT 140 in the wellbore 120.

In a deployment operation, the umbilical 142 may be spooled onto thespool 206 of the TPWT 140, an upper end of the umbilical 142 may beattached to the tree cap 144, and the TPWT 140 may be advanced in thewellbore 120 to a deployment location in a down-hole portion of thewellbore 120, with the umbilical 142 being unspooled from the spool 206as the TPWT 140 is advanced in the wellbore 120. In some embodiments,advancement of the TPWT 140 includes a gravity-driven free-fall of theTPWT 140 in the wellbore 120, followed by thrust-driven propulsion ofthe TPWT 140 that advances the TPWT 140 further into the wellbore 120.For example, the TPWT 140 may be released into a free-fall through afirst/upper portion of the wellbore 120 (such as a vertical portion ofthe wellbore 120) and, upon reaching a trigger point (such as apredefined depth in the wellbore 120), the engine 202 of the TPWT 140may be ignited to generate thrust that propels the TPWT 140 into asecond/lower portion of the wellbore 120 (such as a horizontal portionof the wellbore 120). The TPWT 140 may come to rest in a deploymentlocation, for example, in a down-hole end of the second/lower portion ofthe wellbore 120. The TPWT 140 may come to rest in the deploymentlocation, for example, based on controlling the thrust to slow or stopadvancement of the TPWT 140 at the deployment location, or the TPWT 140running out its fuel source.

During operation, a controller may control operation of the TPWT 140.For example, the controller 208 may control ignition and operation ofthe engine 202 or other navigational elements, such as fins, rudders ordirectional thrust systems, to “fly” the TPWT 140 through the wellbore120. In some embodiments, the controller 208 may control operation ofthe TPWT 140 based on commands received from the well control system 118by way of the umbilical 142.

FIG. 3 is a diagram that illustrates a TPWT tree cap 144 in accordancewith one or more embodiments. In some embodiments, the tree cap 144includes a TPWT tree cap body (“tree cap body”) 300 having a TPWT treecap sealing flange (“tree cap sealing flange”) 302 and defining a TPWTtree cap chamber (“tree cap chamber”) 304, a TPWT retainer 306, and aTPWT tree cap communication port (“tree cap communication port”) 308.The tree cap sealing flange 302 may provide sealing engagement withcomplementary components, such as a sealing flange of the wellhead 130.The tree cap chamber 304 may include a void sized to house a TPWT 140.The tree cap communication port 308 may include a port, such as a sealedbulkhead connector, that provides for communicatively coupling anumbilical 142 of the TPWT 140 to an external communications device, suchas the well control system 118. The sealing nature of the tree capsealing flange 302 and the tree cap communication port 308 may enablethe tree cap chamber 304 to contain high pressure, such as when the TPWTtree cap 144 is assembled to the wellhead 130 and a valve of thewellhead 130 is opened to expose the tree cap chamber 304 to pressure ofthe wellbore 120. The TPWT retainer 306 may include a device adapted toretain a TPWT 140 within the tree cap chamber 304. For example, the TPWTretainer 306 may include a pin, a door or a valve, that can be moved toa closed (or “retain”) position to retain the a TPWT 140 within the treecap chamber 304 and that can be moved to an open (or “release”) positionto release the TPWT 140 from the tree cap 144, allowing the TPWT 140 tofall from, or otherwise exit, the tree cap chamber 304. As described, ina deployment operation, an “loaded” TPWT 140 (having the umbilical 142spooled onto a spool 206 of the TPWT 140) may be inserted into the treecap chamber 304, an upper end of the umbilical 142 may be coupled to thetree cap communication port 308 at an upper end of the tree cap chamber304, the TPWT retainer 306 may be moved into a closed position to retainthe TPWT 140 within the tree cap chamber 304, the “loaded” TPWT tree cap144 (including the TPWT 140 retained within the tree cap chamber 304)may be assembled to a wellhead 130 such that the tree cap sealing flange302 seals with a complementary sealing flange of the wellhead 130, avalve of the wellhead 130 may be opened to expose the tree cap chamber304 to conditions of the wellbore 120 (including wellbore pressure),and, after confirming that no leaks are present in the chamber 304 or atthe tree cap sealing flange 302, the TPWT retainer 306 may be moved toan open position to release the TPWT 140 from the tree cap chamber 304,through a passage of the wellhead 130 and into the wellbore 120.Communication between the TPWT 140 and the well control system 118 maybe provided, before, during or after advancement of the TPWT 140 throughthe wellbore 120, by way of the umbilical 142 and the tree capcommunication port 308.

FIG. 4 is a diagram that illustrates deployment of a TPWT 140 inaccordance with one or more embodiments. Referring to the illustratedembodiment of FIG. 4, deployment of a TPWT 140 into a wellbore 120 of awell 114 may include preparing the TPWT 140 for deployment into thewellbore 120 (as illustrated by element “A”), releasing the TPWT 140into a gravity-driven free-fall in a first/upper-portion of the wellbore120 (as illustrated by element “B”), in response to the TPWT 140reaching a trigger point (represented by trigger point 402), igniting orotherwise activating the engine 202 of the TPWT 140 (as represented byelement “C”) to generate forward thrust that provides thrust-propelledforward advancement of the TPWT 140 in a second/lower-portion of thewellbore 120 (as illustrated by element “D”), with the TPWT 140 comingto rest at a deployment location (represented by deployment location404) within the wellbore 120 (as illustrated by element “E”).

In some embodiments, preparing the TPWT 140 for deployment into thewellbore 120 of the well 114 includes the following: (a) assembling theloaded TPWT 140 into the tree cap chamber 304 of the TPWT tree cap 144;(b) coupling the loaded TPWT tree cap 144 to the wellhead 130 of thewell 114; and (c) conducting a pressure test of the TPWT tree cap 144coupled to the wellhead 130. Assembling the TPWT 140 into the tree capchamber 304 of the TPWT tree cap 144 may include inserting the loadedTPWT 140 (having an umbilical 142 spooled onto the spool 206 of the TPWT140) into the tree cap chamber 304, coupling an upper end of theumbilical 142 to the tree cap communication port 308, and moving theTPWT retainer 306 into a closed position to retain the TPWT 140 withinthe tree cap chamber 304. Coupling the loaded TPWT tree cap 144 to thewellhead 130 of the well 114 may include assembling the loaded TPWT treecap 144 to the wellhead 130 such that the tree cap sealing flange 302seals with a complementary sealing flange of the wellhead 130.Conducting a pressure test of the TPWT tree cap 144 coupled to thewellhead 130 may include opening a valve 406 of the wellhead 130 toexpose the tree cap chamber 304 to conditions of the wellbore 120,including the fluid pressure of wellbore 120.

In some embodiments, releasing the TPWT 140 into a gravity-drivenfree-fall in a first/upper-portion of the wellbore 120 includes movingthe TPWT retainer 306 to an open position to release the TPWT 140 fromthe tree cap chamber 304, such that the TPWT 140 falls through a passageof the wellhead 130 and into the wellbore 120. The engine 202 of theTPWT 140 may not be active during initial advancement of the TPWT 140 inthe wellbore 120, including the duration of the gravity-driven free-fallin the first/upper-portion of the wellbore 120.

In some embodiments, the trigger point is defined by a predetermineddepth within the wellbore 120. For example, the trigger point may be adepth of 1000 meters (m). The trigger point may be specified in the TPWTparameters 134. In such an embodiment, it can be determined that theTPWT 140 has reached the trigger point in response to determining thatthe TPWT 140 is located at a depth of about 1000 m or more. The depth ofthe TPWT 140 may be determined, for example, by way of sensing thepassage of fixed locations within the wellbore 120. This can include acasing collar locator of the TPWT 140 sensing casing collars 128 as theTPWT 140 passes the casing collars 128 while advancing down the wellbore120. In some embodiments, the depth of the TPWT 140 is determined basedon a length of time the TPWT 140 has been in free-fall. For example, ifa trigger point corresponds to a depth of about 1000 m, and it isdetermined that the TPWT 140 will reach a depth of about 1000 m after 30seconds of free-fall, it may be determined that the trigger point of1000 m is reached when the TPWT 140 has been in free-fall for about 30seconds.

In some embodiments, the trigger point is defined by a predeterminedlocation within the wellbore 120. For example, the trigger point may bethe location at which the wellbore transitions from a verticalorientation (for example, the wellbore 120 having a longitudinal axisoriented at about 0° from vertical) to a horizontal orientation (forexample, the wellbore 120 having a longitudinal axis oriented at about45° or more from vertical). In such an embodiment, it may be determinedthat the TPWT 140 has reached the trigger point in response todetermining that the TPWT 140 is oriented at an angle of about 45° ormore from vertical. The orientation of the TPWT 140 may be determined,for example, by way of gyroscope sensors of the TPWT 140 sensing anorientation of the TPWT 140.

In some embodiments, the propelled advancement of the TPWT 140 into thesecond/lower-portion of the wellbore 120 includes operating navigationalelements, such as fins, rudders or directional thrust systems to “fly”the TPWT 140 through the wellbore 120. For example, where the deploymentlocation 404 is located in the motherbore 122 of the wellbore 120, thenavigational elements, such as fins, rudders or directional thrustsystems, may be controlled to direct the TPWT 140 along the motherbore122 to reach the deployment location 404. As a further example, wherethe deployment location 404 is located in the lateral bore 124 of thewellbore 120, the navigational elements, such as fins, rudders ordirectional thrust systems, may be controlled to direct the TPWT 140along the motherbore 122 and into the lateral bore 124, to reach thedeployment location 404. In some embodiments, the TPWT may be “flown”through the wellbore 120 along a predefined route specified in the TPWTparameters 134.

As described, the engine 202 of the TPWT 140 may generate thrust as aresult of consumption of a fuel, such as a solid or liquid propellant.FIG. 5 is a diagram that illustrates an example engine 202 of the TPWT140 in accordance with one or more embodiments. In some embodiments, theengine 202 of the TPWT 140 includes a fuel source 502, a combustionchamber 504, an exhaust port 506 and an igniter 510. In an embodiment inwhich the fuel is a solid propellant, the fuel source 502 may includethe solid propellant. In such an embodiment, the igniter 510 may bepositioned near, adjacent or in the solid propellant, and may beactivated to ignite the solid propellant. The resulting combustion ofthe solid propellant may generate hot gas (or “exhaust gas”) that isexpelled from the exhaust port 506. In an embodiment in which the fuelis a liquid propellant, the fuel source 502 may include a reservoir ofthe liquid propellant and the engine 202 may include a fuel supply valveor pump may that regulates the flow of the liquid propellant into thecombustion chamber 504, which may, in turn, regulate the amount ofliquid propellant consumed and hot gas and thrust generated.

The expulsion of the exhaust gas from the exhaust port 506 may generateforward thrust that propels the TPWT 140 forward (for example, toward adown-hole end of the wellbore 120). The igniter 510 may include anelement that is activated (for example, using power of a battery of thecontroller 208) to ignite the fuel, to cause combustion of the fuel. Insome embodiments, operation of the igniter 510 is controlled by acontroller, such as the TPWT controller 208. The exhaust port 506 mayterminate with an exhaust nozzle 512 which directs the reward expulsionof the exhaust gas from the TPWT 140. The exhaust nozzle 512 may includean external or integrated nozzle. For example, in the illustratedembodiment, the exhaust nozzle 512 includes an integrated cone-shapednozzle formed in the tail end 214 of the body 200 of the TPWT 140.

In some embodiment, the engine 202 of the TPWT 140 is a jet-pump engine.FIG. 6 is a diagram that illustrates an example jet-pump engine 202 ofthe TPWT 140 in accordance with one or more embodiments. In theillustrated embodiment, the jet-pump engine 202 of the TPWT 140 includesa fuel source 602, a combustion chamber 604, an exhaust port 606, anigniter 610, an exhaust nozzle 612, a mixing chamber 614, an inletnozzle 616 and a well fluid inlet 618. During operation, the fuel may beignited and combusted to generate hot gas that is expelled through theinlet nozzle 616 and into the mixing chamber 614, where the hot gas ismixed with well fluid 620 routed into the mixing chamber 614 by way ofthe well fluid inlet 618. The well fluid 620 may include productionfluid or other substances located in the wellbore 120 of the well 114that are routed into the well fluid inlet 618 and the mixing chamber 614as the TPWT 140 advances in the wellbore 120. The hot gases may mix withthe well fluid 620 in the mixing chamber 614 and then be expelledthrough a throat 622 and exhaust nozzle 612 of the exhaust port 606. Theaddition of the well fluid 620 may increase the volume of substancesbeing expelled from the exhaust port 606, resulting in a relativeincrease of thrust generated by the engine 202. The expulsion of themixture of hot gas and well fluids (or “exhaust gas”) from the exhaustport 606 may generate forward thrust that propels the TPWT 140 forward(for example, toward a down-hole end of the wellbore 120). The igniter610 may include an element that is activated (for example, using powerof a battery of the controller 208) to ignite the fuel, to causecombustion of the fuel. In some embodiments, operation of the igniter610 is controlled by a controller, such as the TPWT controller 208. Theexhaust port 606 may terminate with the exhaust nozzle 612, whichdirects the reward expulsion of the exhaust gas from the TPWT 140. Theexhaust nozzle 612 may include an external or integrated nozzle. Forexample, in the illustrated embodiment, the exhaust nozzle 612 includesan integrated cone-shaped nozzle formed in the tail end 214 of the body200 of the TPWT 140.

In some embodiments, the TPWT 140 includes navigational elements, suchas fins, rudders, or directional thrust systems. The navigationalelements may assist in directing the TPWT 140 through the wellbore 120.FIG. 6 is a diagram that illustrates example navigational elements ofthe TPWT 140 in accordance with one or more embodiments. In theillustrated embodiment, the TPWT 140 includes an engine 202 similar tothat described with regard to FIG. 5, although other engines, such asthe pump-jet engine of FIG. 6, may be employed. The illustrated TPWT 140includes stabilizers 702, including fins or rudders, and a directionalthrust system 706, including a directional exhaust nozzle 708 and areverse thrust system 710. A TPWT 140 may include a combination of someor all of the navigational elements described. In the illustratedembodiment, the stabilizers 700 include forward stabilizers 712 andrearward stabilizers 714. In some embodiments, the stabilizers 702include fins or rudders. For example, the forward stabilizers 712 mayinclude fins and the rearward stabilizers 714 may include rudders. A finmay include a fixed stabilizer (for example, a fixed fin elementextending laterally from the body 200) that reduce aerodynamic side slipof the TPWT 140. A rudder may include a movable stabilizer (for example,a rotating fin element extending laterally from the body 200) thatprovides for steering of the TPWT 140. In some embodiments some of allof the stabilizers 702 may include a combination of a fin and a rudder.For example, a stabilizer 702 may include a wing including a fixedforward fin element extending laterally from the body 200, and arotating fin element extending from a trailing end of the fixed forwardfin element. The fin element may provide for stabilizing the TPWT 140and the rudder element may provide for steering of the TPWT 140. In someembodiments, the forward stabilizers 712 include fins and the rearwardstabilizers 714 include rudders or wings.

In some embodiments, the directional thrust system 706 provides fordirecting thrust generated by the engine 202 of the TPWT 140 to assistin controlling movement and direction of the TPWT 140. For example thedirectional exhaust nozzle 708 may include a gimbal mounted exhaustnozzle of the TPWT 140 that can be swiveled to guide a direction of thethrust generated by the engine 202 of the TPWT 140. The resulting changein direction of the thrust can steer the TPWT 140 in differentdirections. Accordingly, the direction of the directional exhaust nozzle708 may be controlled to steer the TPWT 140 in different directions. Insome embodiments, the direction of the directional exhaust nozzle 708 iscontrolled by a controller, such as the TPWT controller 208.

As a further example, the reverse thrust system 710 may include aconduit that can be selectively engaged to direct thrust in a forwarddirection to generate reverse thrust to, for example, slow or stopmovement of the TPWT 140 in the forward direction. In the illustratedembodiment, the TPWT 140 includes elements similar to those describedwith regard to the engine 202 of FIG. 5, in addition to a reverse thrustsystem 710 that includes a forward thrust control valve 718, a reversethrust control valve 720, a reverse thrust passage 722 and a reversethrust port 724. The forward thrust control valve 718 may be a throttlevalve that is operable to regulate the flow of hot gas (or “exhaustgas”) into the exhaust port 506 and, in turn, regulate the amount offorward thrust generated by the engine 202. The reverse thrust controlvalve 720 may be a throttle valve that is operable to regulate the flowof hot gas (or “exhaust gas”) through the reverse thrust passage 722 andthe reverse thrust port 724 and, in turn, regulate the amount of reversethrust generated by the engine 202. During a reverse thrust operation,the reverse thrust control valve 720 may be at least partially opened orthe forward thrust control valve may be at least partially closed, todirect hot gas (or “exhaust gas”) through the reverse thrust passage 722and the reverse thrust port 724. The expulsion of the exhaust gas fromthe reverse thrust port 724 may result in thrust in the forwarddirection to generate reverse thrust to, for example, slow or stopmovement of the TPWT 140 in the forward direction (for example, toward adown-hole end of the wellbore 120). In some embodiments, the reversethrust is of sufficient magnitude to cause the movement of the TPWT 140in the reverse direction (for example, toward an up-hole end of thewellbore 120). In some embodiments, operation of the forward thrustcontrol valve 718 or the reverse thrust control valve 720 is controlledby a controller, such as the TPWT controller 208. A similar reversethrust system may be incorporated in a TPWT 140 having a jet-pump styleengine. For example, referring to FIG. 6, a similar reverse thrustpassage may extend from the combustion chamber 604 or the mixing chamber614, with a reverse thrust control valve regulating flow through thereverse thrust passage, and a forward thrust control valve locatedbetween the combustion chamber 604 and the mixing chamber 614 (orbetween the mixing chamber 614 and the exhaust port 606) regulating flowthrough the exhaust port 606.

In some embodiments, the TPWT 140 includes a locating system, such as acasing collar locator (“CCL”) that is operable to sense casing collars128 as the TPWT 140 passes the casing collars 128 while advancing downthe wellbore 120. FIG. 8 is a diagram that illustrates an example casingcollar locator (“CCL”) 800 of the TPWT 140 in accordance with one ormore embodiments. In the illustrated embodiment, the CCL 800 includes atwo CCL coils 802 a and 802 b residing radially internal to the recessof the spool 206. Each of the coils 802 a and 802 b may include a coilof electrically conductive wire (for example, copper wire) that iswrapped into respective circumferential depressions (or “recesses”) 804a and 804 b that extend radially inward from the recess forming thespool 206. During use, the coils 802 a and 802 b may be electrified tocreate an electromagnet that is capable of sensing changes in magneticfield caused by changes in tubular thickness of a surrounding metaltubular in the wellbore 120, such as the casing 126. As the TPWT 140travels through the wellbore 120 and passes the locations at which asurrounding metal tubular changes in thickness, such as at a casingcollars 128, the coils 802 a and 802 b may detect a corresponding changein magnetic field, in sequence, and the change can be attributed to theTPWT 140 being located at or passing the location of the change. Forexample, as the TPWT 140 travels through the wellbore 120 and passes thefirst casing collar 128 known to be at a depth of 100 m, the coils 802 aand 802 b may detect a first change in magnetic field at a first time,and it can be determined that the TPWT 140 is located at the depth of100 m at the first time. As the TPWT 140 continues to travel through thewellbore 120 and passes the second casing collar 128 known to be at adepth of 200 m, the coils 802 a and 802 b may detect a second change inmagnetic field at a second time, and it can be determined that the TPWT140 is located at the depth of 200 m at the second time, and so forth.

In some embodiments, the TPWT 140 is used to deploy acoustic sensors,such as FO line, for DAS. DAS may be used, for example, for verticalseismic profiling of a well. FIG. 9 is a diagram that illustratesdeployment of a DAS FO line into a wellbore 120 of the well 114 inaccordance with one or more embodiments. In the illustrated embodiment,the umbilical 142 includes a DAS FO line 900. When the TPWT 140 isdeployed into the well 114, the DAS FO line may be unspooled into thewellbore 120, resulting in the DAS FO line 900 being distributed atalong a length of the wellbore 120. In some embodiments, an interrogator904 coupled to the DAS FO line 900, such as the well control system 118,monitors seismic events sensed by the DAS FO line 900. The seismicevents may be seismic echoes resulting, for example, from seismicsignals generated by an array of seismic sources 906 located at thesurface 112.

In some embodiments, the DAS FO line 900 forming the umbilical 142 issized to facilitate contact between the DAS FO line 900 and a lining ofthe wellbore 120, such as an interior wall of the casing 126. Forexample, a DAS FO line 900 may have a length that is about 125% of alength portion of the wellbore 120 to be lined with the DAS FO line 900.This extra length may facilitate the DAS FO line 900 expanding radial toadhere (or “stick”) to the tubular walls, such as the interior walls ofthe casing 126, by way of surface tension. As a result, the DAS FO line900 may take a spiral or helical shape, sticking to the tubular walls ofthe wellbore 120. The resulting coupling of the DAS FO line 900 with thetubular walls can help to reduce attenuation of seismic events sensed bythe DAS FO line 900.

FIG. 10 is a diagram that illustrates deployment of U-bend style DAS FOline into multiple wellbores in accordance with one or more embodiments.In the illustrated embodiment, the umbilical 142 includes a U-bend styleDAS FO line 1000 deployed into multiple wellbores 120 a and 120 b ofrespective wells 114 a and 114 b by way of respective TPWTs 140 a and140 b. The DAS FO line 1000 may include multiple down-hole portions 1002a and 1002 b that are each deployed into respective wellbore 120 a and120 b. The down-hole portions 1002 a and 1002 b may each include firstand second DAS FO segments 1004 a and 1004 b that are connected to oneanother by way of a U-bend 1006. The U-bend 1006 may include a rigid180° bend in the DAS FO line that provides a curved transition betweenthe first and second DAS FO line segments 1004 a and 1004 b. In someembodiments, the U-bend 1006 includes a “mini-bend”, such as a MiniBend®Fiber Optic Component, provided by AFL, having headquarters in Duncan,S.C., USA.

During a deployment operation for each of the respective wellbores 120 aand 120 b, the respective down-hole portion 1002 a or 1002 b of theU-bend style DAS FO line 1000 may be spooled onto a spool 206 of therespective TPWTs 140 a or 140 b, and the TPWTs 140 a or 140 b may bedeployed into the respective wellbores 120 a or 120 b to deploy therespective down-hole portions 1002 a or 1002 b into the respectivewellbores 120 a or 120 b. As illustrated, as a result of a deploymentoperation, the TPWT 140 a and 140 b and the respective the down-holeportions 1002 a and 1002 b may be deposited in a down-hole portion ofthe respective wellbore 120 a and 120 b, with each of the first andsecond DAS FO segments 1004 a and 1004 b of the down-hole portions 1002a and 1002 b extending along the respective wellbores 120 a and 120 b,to the surface 112. In some embodiments, an interrogator 1010 coupled tothe DAS FO line 1000, such as the well control system 118, monitorsseismic events sensed by the respective down-hole portions 1002 a and1002 b of the DAS FO line 1000. The seismic events may be seismic echoesresulting, for example, from seismic signals generated by an array ofseismic sources 1012 located at the surface 112.

In some embodiments, the U-bend 1006 of a down-hole segment 1002 of aU-bend style DAS FO line 1000 is wrapped about a spool 206 of a TPWT 140in a manner to maintain and protect the curved shape of the U-bend 1006.As illustrated in FIG. 11, in some embodiments, the U-bend 1006 of thedown-hole segment 1002 of the U-bend style DAS FO line 1000 is wrappedabout a circumference of the spool 206 of the TPWT 140 to maintain andprotect the curved shape of the U-bend 1006. In such an embodiment,loading of the spool 206 may include wrapping the U-bend 1006 about thecircumference of the spool 206, and subsequently winding the down-holesegment 1002 of the U-bend style DAS FO line 1000 about the U-bend 1006or the circumference of the spool 206. As illustrated in FIG. 12, insome embodiments, the U-bend 1006 is secured to a face of the spool 206,with the down-hole segment 1002 of the U-bend style DAS FO line 1000being wrapped about a circumference of the spool 206 of the TPWT 140 tomaintain and protect the curved shape of the U-bend 1006. For example,the U-bend 1006 may be “tucked” under wraps of the down-hole segment1002 of the U-bend style DAS FO line 1000 to maintain and protect thecurved shape of the U-bend 1006. In such an embodiment, loading of thespool 206 may include placing the U-bend 1006 against a surface of thespool 206, and subsequently winding the down-hole segment 1002 of theU-bend style DAS FO line 1000 about the U-bend 1006 and thecircumference of the spool 206. Such a tucked configuration may besuitable for use with a mini-bend type U-bend 1006. For example, amini-bend type U-bend 1006 may be tucked under wraps of the down-holesegment 1002 of the U-bend style DAS FO line 1000 to maintain andprotect the curved shape of the U-bend 1006.

FIG. 13 is a flowchart diagram that illustrates a method of DAS sensing1300 in accordance with one or more embodiments. The method 1300 mayinclude deploying a DAS FO line into a wellbore using a TPWT (block1302). In some embodiments, deploying DA FO line into a wellboreincludes deploying a DAS FO line into one or more wellbores using one ormore TPWTs. For example, deploying DAS FO line into a wellbore using aTPWT may include deploying the DAS FO line 900 into the wellbore 120, asdescribed with regard to at least FIG. 9. As a further example,deploying a DAS FO line into a wellbore using a TPWT may includedeploying the U-bend style DAS FO line 1000 into the wellbores 120 a and120 b, as described with regard to at least FIG. 10.

The method 1300 may include deploying seismic sources (block 1304). Insome embodiments, deploying seismic sources includes deploying one ormore seismic generators operable to generate seismic signals. Forexample, deploying seismic sources may include positioning an array ofseismic sources 906 at the surface 112, as described with regard to atleast FIG. 9. As a further example, deploying seismic sources mayinclude positioning an array of seismic sources 1012 at the surface 112,as described with regard to at least FIG. 10.

The method 1300 may include activating the seismic sources to generateseismic signals (block 1306) and recording resulting seismic signalsreceived at the DAS FO line (block 1308). In some embodiments,activating the seismic sources to generate seismic signals includesoperating the seismic sources to generate seismic signals that penetratea formation. For example, activating the seismic sources to generateseismic signals may include an interrogator, such as the well controlsystem 118, controlling the seismic sources 906 or 1012 to generateseismic signals that penetrate the formation 104. In some embodiments,recording resulting seismic signals received at the DAS FO line includesrecording seismic signals sensed at the DAS FO line. For example, withregard to the DAS FO line 900 described with regard to at least FIG. 9,recording resulting seismic signals received at the DAS FO line mayinclude the well control system 118 recording seismic signals sensed asdiscrete locations along the portion of the DAS FO line 900 located inthe wellbore 120. As a further example, with regard to the DAS FO line1000 described with regard to at least FIG. 10, recording resultingseismic signals received at the DAS FO line may include the well controlsystem 118 recording seismic signals simultaneously sensed along thefirst and second DAS FO segments 1004 a and 1004 b of the down-holeportions 1002 a and 1002 b disposed in the wellbores 120 a and 120 b.

In some embodiments, various operations can be undertaken based on theseismic data obtained by way of a DAS FO line. For example, the recordedacoustic data can be used to determine characteristics of the formation104 and the reservoir 102, which can in turn be used to determineappropriate operating parameters for the well 114 (or wells 114 a and114 b), such as production rates or production pressures for the well114 (or wells 114 a and 114 b), or to determine appropriate locationsand trajectories for additional wells in the formation 104. The well 114(or wells 114 a and 114 b), or other wells in the formation 104, can beoperated in accordance with the determined operating parameters, orother wells can be drilled into the formation 104 at the locations andwith the trajectories determined.

FIG. 14 is a flowchart diagram that illustrates a method of deploying aTPWT into a well 1400 accordance with one or more embodiments. Themethod 1400 may include preparing a TPWT for deployment in a wellbore(block 1402). In some embodiments, preparing a TPWT for deployment in awellbore includes preparing a TPWT 140 for deployment into a wellbore120 of a well 114. For example, preparing the TPWT 140 for deploymentmay include a well operator performing the following operations: (a)loading a spool 206 of a TPWT 140 with an umbilical 142 (for example, aFO line, a DAS FO line or a U-bend style DAS FO line); (a) assemblingthe TPWT 140 into a tree cap chamber 304 of a TPWT tree cap 144; (b)coupling the “loaded” TPWT tree cap 144 to a wellhead 130 of the well114; and (c) conducting a pressure test of the TPWT tree cap 144 coupledto the wellhead 130.

The method 1400 may include releasing the TPWT into a gravity-drivenfree-fall in the wellbore (block 1404). In some embodiments, releasingthe TPWT into a gravity-driven free-fall in the wellbore includesreleasing the loaded TPWT 140 into a gravity-driven free-fall in afirst/upper-portion of the wellbore 120. For example, the well controlsystem 118 or other well operator may control operation of the tree cap144 to move the TPWT retainer 306 to an open position to release theTPWT 140 from the tree cap chamber 304, such that the TPWT 140 fallsthrough the wellhead 130 and into a first/upper-portion of the wellbore120.

The method 1400 may include determining whether the TPWT has reached atrigger point (block 1406). In some embodiments, determining whether theTPWT has reached a trigger point includes monitoring advancement of theTPWT within the wellbore 120 to determine whether the TPWT 140 hasreached a trigger point. For example, a controller, such as a the wellcontrol system 118 or the TPWT controller 208, may determine, based on atimed duration of the fall or navigational data indicative of a speed,location or orientation of the TPWT 140, whether the TPWT 140 hasreached the trigger point 402.

The method 1400 may include, in response to determining that the TPWThas reached the trigger point, conducting propelled advancement of theTPWT in the wellbore to a deployment location in the wellbore (block1408). In some embodiments, conducting propelled advancement of the TPWTin the wellbore to a deployment location in the wellbore includesoperating the engine 202 of the TPWT 140 to generate thrust to propelthe TPWT 140 into the second/lower-portion of the wellbore 120, with theTPWT 140 coming to rest at a deployment location 404 in the wellbore120. For example, a controller, such as a the well control system 118 orthe TPWT controller 208, may control the ignition and operation of theengine 202 and control operation of other navigational elements, such asfins, rudders or directional thrust systems to “fly” the TPWT 140through the wellbore 120, to the deployment location 404. In someembodiments, control of the TPWT 140 is provided by navigationalcommands initiated locally by the TPWT controller 208, or navigationalcommands provided to the TPWT controller 208, from the well controlsystem 118 by way of the umbilical 142.

The method 1400 may include monitoring the payload of the TPWT (block1410). In some embodiments, monitoring the payload of the TPWT includesmonitoring data received from the payload 204 of the TPWT 140. Forexample, where the payload 204 includes BHP sensors or BHT sensors, acontroller, such as the well control system 118, may monitor operationaldata, including BHP data and BHT data indicative of the BHP or BHT atthe deployment location 404 in the wellbore 120. As a further example,where the payload 204 includes a DAS FO line, a controller, such as athe well control system 118, may monitoring operational data, includingacoustic data indicative of seismic events sensed by the DAS FO line 900or 1000 deployed in the wellbore 120.

In some embodiments, various operations can be undertaken based on thedata obtained by way of a payload 204 of a TPWT 140 deployed into a well114. For example, where the payload 204 includes BHP sensors or BHTsensors, the corresponding BHP data and BHT data can be used todetermine a BHP and BHT for the well 114, which can, in turn, be used todetermine appropriate operating parameters for the well 114, such asproduction rates or production pressures for the well 114, and the well114, or other wells in the formation 104, can be operated in accordancewith the determined operating parameters. As a further example, wherethe payload 204 includes a DAS FO line, the acoustic data can be used todetermine characteristics of the formation 104 and the reservoir 102,which can, in turn, be used to determine appropriate operatingparameters for the well 114, such as production rates or productionpressures for the well 114, or to determine appropriate locations andtrajectories for additional wells in the formation 104. The well 114, orother wells in the formation 104, can be operated in accordance with thedetermined operating parameters, or other wells can be drilled into theformation at the locations and with the trajectories determined.

FIG. 15 is a diagram that illustrates an example computer system (or“system”) 2000 in accordance with one or more embodiments. In someembodiments, the system 2000 includes a memory 2004, a processor 2006and an input/output (I/O) interface 2008. The memory 2004 may includenon-volatile memory (for example, flash memory, read-only memory (ROM),programmable read-only memory (PROM), erasable programmable read-onlymemory (EPROM), electrically erasable programmable read-only memory(EEPROM)), volatile memory (e.g., random access memory (RAM), staticrandom access memory (SRAM), synchronous dynamic RAM (SDRAM)), or bulkstorage memory (for example, CD-ROM or DVD-ROM, hard drives). The memory2004 may include a non-transitory computer-readable storage mediumhaving program instructions 2010 stored thereon. The programinstructions 2010 may include program modules 2012 that are executableby a computer processor (for example, the processor 2006) to cause thefunctional operations described, such as those described with regard tothe well control system 118, the TPWT controller 208, the method 1300 orthe method 1400.

The processor 2006 may a processor capable of executing the programinstructions 2010. For example, the processor 2006 may include a centralprocessing unit (CPU) that carries out program instructions (forexample, the program instructions of the program modules 2012) toperform the arithmetical, logical, or input/output operations describedhere. The processor 2006 may include one or more processors. The I/Ointerface 2008 may provide an interface for communication with one ormore I/O devices 2014, such as a joystick, a computer mouse, a keyboard,or a display screen (for example, an electronic display for displaying agraphical user interface (GUI)). The I/O devices 2014 may be connectedto the I/O interface 2008 by way of a wired connection (for example, anIndustrial Ethernet connection) or a wireless connection (for example, aWi-Fi connection). The I/O interface 2008 may provide an interface forcommunication with one or more external devices 2016. In someembodiments, the I/O interface 2008 includes one or both of an antennaand a transceiver. In some embodiments, the external devices 2016include sensors or other computer systems.

Further modifications and alternative embodiments of various aspects ofthe disclosure will be apparent to those skilled in the art in view ofthis description. Accordingly, this description is to be construed asillustrative only and is for the purpose of teaching those skilled inthe art the general manner of carrying out the embodiments. It is to beunderstood that the forms of the embodiments shown and described hereare to be taken as examples of embodiments. Elements and materials maybe substituted for those illustrated and described here, parts andprocesses may be reversed or omitted, and certain features of theembodiments may be utilized independently, all as would be apparent toone skilled in the art after having the benefit of this description ofthe embodiments. Changes may be made in the elements described herewithout departing from the spirit and scope of the embodiments asdescribed in the following claims. Headings used here are fororganizational purposes only and are not meant to be used to limit thescope of the description.

It will be appreciated that the processes and methods described here areexample embodiments of processes and methods that may be employed inaccordance with the techniques described here. The processes and methodsmay be modified to facilitate variations of their implementation anduse. The order of the processes and methods and the operations providedmay be changed, and various elements may be added, reordered, combined,omitted, modified, and so forth. Portions of the processes and methodsmay be implemented in software, hardware, or a combination of softwareand hardware. Some or all of the portions of the processes and methodsmay be implemented by one or more of the processors/modules/applicationsdescribed here.

As used throughout this application, the word “may” is used in apermissive sense (that is, meaning having the potential to), rather thanthe mandatory sense (that is, meaning must). The words “include,”“including,” and “includes” mean including, but not limited to. As usedthroughout this application, the singular forms “a”, “an,” and “the”include plural referents unless the content clearly indicates otherwise.Thus, for example, reference to “an element” may include a combinationof two or more elements. As used throughout this application, the term“or” is used in an inclusive sense, unless indicated otherwise. That is,a description of an element including A or B may refer to the elementincluding one or both of A and B. As used throughout this application,the phrase “based on” does not limit the associated operation to beingsolely based on a particular item. Thus, for example, processing “basedon” data A may include processing based at least in part on data A andbased at least in part on data B, unless the content clearly indicatesotherwise. As used throughout this application, the term “from” does notlimit the associated operation to being directly from, unless indicatedotherwise. Thus, for example, receiving an item “from” an entity mayinclude receiving an item directly from the entity or indirectly fromthe entity (for example, by way of an intermediary entity). Unlessspecifically stated otherwise, as apparent from the discussion, it isappreciated that throughout this specification discussions utilizingterms such as “processing,” “computing,” “calculating,” “determining” orthe like may refer to actions or processes of a specific apparatus, suchas a special purpose computer or a similar special purpose electronicprocessing/computing device. In the context of this specification, aspecial purpose computer or a similar special purpose electronicprocessing/computing device is capable of manipulating or transformingsignals, typically represented as physical, electronic or magneticquantities within memories, registers, or other information storagedevices, transmission devices, or display devices of the special purposecomputer or similar special purpose electronic processing/computingdevice.

What is claimed is:
 1. A method of deploying distributed acoustic sensing (DAS) sensors in a subterranean well, the method comprising: releasing a torpedo into gravity-driven advancement within a first portion of a wellbore of a subterranean well, the torpedo comprising: a distributed acoustic sensing (DAS) fiber-optic (FO) umbilical that is physically coupled to a surface component and configured to unspool from the torpedo as the torpedo advances in the wellbore; and an engine configured to generate thrust to propel advancement of the torpedo in the wellbore; determining that the torpedo has reached a trigger point comprising a predefined depth within the wellbore; and activating, in response to determining that the torpedo has reached the trigger point within the wellbore, the engine to generate forward thrust to propel the torpedo within a horizontal portion of the wellbore such that at least some of the DAS FO umbilical is disposed in the horizontal portion of the wellbore, and the torpedo comes to rest at a deployment location within the wellbore.
 2. A method of distributed acoustic sensing in a subterranean well, the method comprising: advancing a torpedo into a first portion of a wellbore of a subterranean well, the torpedo comprising: a distributed acoustic sensing (DAS) fiber-optic (FO) umbilical that is physically coupled to a surface component and configured to unspool from the torpedo as the torpedo advances in the wellbore; and an engine configured to generate thrust to propel the torpedo; determining that the torpedo has reached a trigger point comprising a predefined depth within the wellbore; and activating, in response to determining that the torpedo has reached the trigger point within the wellbore, the engine to generate thrust to propel advancement of the torpedo within a second portion of the wellbore such that at least some of the DAS FO umbilical is disposed in the second portion of the wellbore.
 3. The method of claim 2, wherein subsequent to the torpedo coming to rest in the deployment location, the DAS FO umbilical extends from the surface component into the second portion of the wellbore.
 4. The method of claim 2, further comprising, subsequent to the torpedo coming to rest at the deployment location within the wellbore, conducting a seismic operation comprising sensing seismic events by way of the DAS FO umbilical unspooled in the wellbore.
 5. The method of claim 4, further comprising positioning a plurality of seismic sources at surface locations, wherein the seismic operation further comprises operating the seismic sources to generate seismic signals, and wherein the seismic events correspond to the seismic signals generated.
 6. The method of claim 2, further comprising, subsequent to the torpedo coming to rest at the deployment location within the wellbore, conducting a fluid flow monitoring operation comprising sensing fluid flow by way of the DAS FO umbilical unspooled in the wellbore.
 7. The method of claim 2, further comprising, subsequent to the torpedo coming to rest at the deployment location within the wellbore, conducting a leak monitoring operation comprising sensing a leak by way of the integrated acoustic sensors of the DAS FO umbilical unspooled in the wellbore.
 8. The method of claim 2, wherein the DAS FO umbilical comprises a single segment of FO line.
 9. The method of claim 2, wherein the DAS FO line comprises a U-bend style DAS FO line comprising a first segment of the DAS FO line and a second segment of the DAS FO line connected by way of a U-bend.
 10. The method of claim 9, wherein the torpedo comprises a cylindrical spool, the method further comprising wrapping the U-bend about a circumference of the spool, and wrapping the first and second segments of the DAS FO line about the U-bend wrapped about the circumference of the spool.
 11. The method of claim 9, wherein the torpedo comprises a cylindrical spool, the method further comprising disposing the U-bend on a surface of the spool, and wrapping the first and second segments of the DAS FO line about the U-bend disposed on the surface of the spool.
 12. The method of claim 9, wherein the U-bend comprises a mini-bend connector.
 13. The method of claim 9, wherein a first portion of the DAS FO umbilical comprising the a first segment of the DAS FO, the second segment of the DAS FO line and the U-bend is disposed in the wellbore using the torpedo, the method further comprising deploying a second portion of the DAS FO umbilical into a second wellbore using a second torpedo, the second portion of the DAS FO umbilical comprising a third segment of the DAS FO line and a fourth segment of the DAS FO line connected by way of a second U-bend.
 14. The method of claim 13, further comprising conducting a seismic operation comprising sensing seismic events by way of the first portion of the DAS FO umbilical disposed in the wellbore and the second portion of the DAS FO umbilical disposed in the second wellbore.
 15. The method of claim 2, wherein the torpedo comprises a body formed of a dissolvable material configured to dissolve in the wellbore, the method further comprising leaving the torpedo at the deployment location such that the body of the torpedo dissolves at the deployment location within the wellbore.
 16. The method of claim 2, wherein the DAS FO umbilical is coupled to a well control system and is configured to facilitate communication between the torpedo and the well control system, the method further comprising the well control system receiving data from the torpedo by way of the DAS FO umbilical.
 17. The method of claim 2, wherein the second portion of the wellbore comprises a horizontal portion of the wellbore.
 18. The method of claim 2, wherein the first portion of the wellbore comprises a vertical portion of the wellbore and the second portion of the wellbore comprises a horizontal portion of the wellbore, and wherein the trigger point within the wellbore comprises a point of transition between the vertical portion of the wellbore and the horizontal portion of the wellbore.
 19. A non-transitory computer readable storage medium comprising program instructions stored thereon that are executable by a processor to cause the following operations: advancing a torpedo into a first portion of a wellbore of a subterranean well, the torpedo comprising: a distributed acoustic sensing (DAS) fiber-optic (FO) umbilical that is physically coupled to a surface component and configured to unspool from the torpedo as the torpedo advances in the wellbore; and an engine configured to generate thrust to propel the torpedo; determining that the torpedo has reached a trigger point comprising a predefined depth within the wellbore; and activating, in response to determining that the torpedo has reached the trigger point within the wellbore, the engine to generate thrust to propel advancement of the torpedo within a second portion of the wellbore such that at least some of the DAS FO umbilical is disposed in the second portion of the wellbore.
 20. A subterranean well torpedo system comprising: a control system; and a torpedo comprising: a distributed acoustic sensing (DAS) fiber-optic (FO) umbilical that is physically coupled to a surface component and configured to unspool from the torpedo as the torpedo advances in the wellbore; and an engine configured to generate thrust to propel the torpedo; the control system configured to: advance the torpedo into a first portion of the wellbore of the subterranean well; determine that the torpedo has reached a trigger point comprising a predefined depth within the wellbore; and activate, in response to determining that the torpedo has reached the trigger point within the wellbore, the engine to generate thrust to propel the torpedo within a second portion of the wellbore such that at least some of the DAS FO umbilical is disposed in the second portion of the wellbore.
 21. The system of claim 20, wherein the first portion of the wellbore comprises a vertical portion of the wellbore and the second portion of the wellbore comprises a horizontal portion of the wellbore, and wherein the trigger point within the wellbore comprises a point of transition between the first wellbore portion and the second wellbore portion of the wellbore.
 22. The system of claim 20, wherein the DAS FO umbilical has a length that is at least 25% greater than a distance between the surface component and a target deployment location within the wellbore.
 23. The system of claim 20, wherein subsequent to the torpedo coming to rest in the deployment location, the DAS FO umbilical extends from the surface component into the second portion of the wellbore.
 24. The system of claim 20, wherein the control system is further configured to, subsequent to the torpedo coming to rest at the deployment location within the wellbore, conduct a seismic operation comprising sensing seismic events by way of the DAS FO umbilical unspooled in the wellbore.
 25. The system of claim 24, wherein a plurality of seismic sources are positioned at surface locations, and wherein the seismic operation further comprises operating the seismic sources to generate seismic signals, and wherein the seismic events correspond to the seismic signals generated.
 26. The system of claim 20, wherein the control system is further configured to, subsequent to the torpedo coming to rest at the deployment location within the wellbore, conduct a fluid flow monitoring operation comprising sensing fluid flow by way of the DAS FO umbilical unspooled in the wellbore.
 27. The system of claim 20, wherein the control system is further configured to, subsequent to the torpedo coming to rest at the deployment location within the wellbore, conduct a leak monitoring operation comprising sensing a leak by way of the DAS FO umbilical unspooled in the wellbore.
 28. The system of claim 20, wherein the DAS FO umbilical comprises a single segment of FO line.
 29. The system of claim 20, wherein the DAS FO line comprises a U-bend style DAS FO line comprising a first segment of the DAS FO line and a second segment of the DAS FO line connected by way of a U-bend.
 30. The system of claim 29, wherein the torpedo comprises a cylindrical spool, and wherein the U-bend is wrapped about a circumference of the spool, with the first and second segments of the DAS FO line wrapped about the U-bend wrapped about the circumference of the spool.
 31. The system of claim 29, wherein the torpedo comprises a cylindrical spool, and wherein the U-bend is disposed on a surface of the spool, with the first and second segments of the DAS FO line wrapped about the U-bend disposed on the surface of the spool.
 32. The system of claim 29, wherein the U-bend comprises a mini-bend connector.
 33. The system of claim 29, wherein a first portion of the DAS FO umbilical comprises the first segment of the DAS FO, the second segment of the DAS FO line and the U-bend, the first portion of the DAS FO line is disposed in the wellbore using the torpedo, and a second portion of the DAS FO umbilical is disposed in a second wellbore, the second portion of the DAS FO umbilical comprising a third segment of the DAS FO line and a fourth segment of the DAS FO line connected by way of a second U-bend.
 34. The system of claim 33, wherein the control system is further configured to conduct a seismic operation comprising sensing seismic events by way of the first portion of the DAS FO umbilical disposed in the wellbore and the second portion of the DAS FO umbilical disposed in the second wellbore.
 35. The system of claim 20, wherein the torpedo comprises a body formed of a dissolvable material configured to dissolve in the wellbore.
 36. The system of claim 20, wherein the DAS FO umbilical is coupled to a well control system and is configured to facilitate communication between the torpedo and the well control system.
 37. The system of claim 20, wherein the second portion of the wellbore comprises a horizontal portion of the wellbore. 